ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934

For
the fiscal year ended December 31,
2008

o

TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934

For
the transition period from __________
to_________

Commission

File Number

Registrants;
States of Incorporation;

Address and Telephone
Number

I.R.S.
Employer

Identification Nos.

1-3525

American
Electric Power Company, Inc. (A New York Corporation)

13-4922640

1-3457

Appalachian
Power Company (A Virginia Corporation)

54-0124790

1-2680

Columbus
Southern Power Company (An Ohio Corporation)

31-4154203

1-3570

Indiana
Michigan Power Company (An Indiana Corporation)

35-0410455

1-6543

Ohio
Power Company (An Ohio Corporation)

31-4271000

0-343

Public
Service Company of Oklahoma (An Oklahoma Corporation)

73-0410895

1-3146

Southwestern
Electric Power Company (A Delaware Corporation)

1
Riverside Plaza, Columbus, Ohio 43215

Telephone
(614) 716-1000

72-0323455

Indicate
by check mark if the registrants with respect to American Electric Power
Company, Inc., Appalachian Power Company and Ohio Power Company, is each a
well-known seasoned issuer, as defined in Rule 405 on the Securities
Act.

Yes x

No. o

Indicate
by check mark if the registrants with respect to Columbus Southern Power
Company, Indiana Michigan Power Company, Public Service Company of
Oklahoma and Southwestern Electric Power Company, are well-known seasoned
issuers, as defined in Rule 405 on the Securities Act.

Yes o

No. x

Indicate
by check mark if the registrants are not required to file reports pursuant
to Section 13 or Section 15(d) of the Exchange Act.

Yes o

No. x

Indicate
by check mark whether the registrants (1) have filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past 90 days.

Yes x

No. o

Indicate
by check mark if disclosure of delinquent filers with respect to
Appalachian Power Company, Ohio Power Company, Public Service Company of
Oklahoma or Southwestern Electric Power Company pursuant to Item 405 of
Regulation S-K (229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive
proxy or information statements of Appalachian Power Company, Ohio Power
Company, Public Service Company of Oklahoma or Southwestern Electric Power
Company incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.

x

Indicate
by check mark whether American Electric Power Company, Inc. is a large
accelerated filer, an accelerated filer, a non-accelerated filer or a
smaller reporting company. See definitions of ‘large
accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in
Rule 12b-2 of the Exchange Act. (Check One)

Large
accelerated filer x

Accelerated
filer

o

Non-accelerated
filer o (Do not check if
a smaller reporting company)

Smaller
reporting company

o

Indicate
by check mark whether Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Ohio Power Company, Public
Service Company of Oklahoma and Southwestern Electric Power Company are
large accelerated filers, accelerated filers, non-accelerated filers or
smaller reporting companies. See definitions of ‘large
accelerated filer’, ‘accelerated filer’ and ‘smaller reporting company’ in
Rule 12b-2 of the Exchange Act. (Check One)

Large
accelerated filer o

Accelerated
filer

o

Non-accelerated
filer x (Do not check if
a smaller reporting company)

Smaller
reporting company

o

Indicate
by check mark if the registrants are shell companies, as defined in Rule
12b-2 of the Exchange Act.

Yes o

No. x

Columbus
Southern Power Company and Indiana Michigan Power Company meet the conditions
set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore
filing this Form 10-K with the reduced disclosure format specified in General
Instruction I(2) to such Form 10-K.

Securities
registered pursuant to Section 12(b) of the Act:

Registrant

Title of each class

Name
of each exchange

on
which registered

American
Electric Power Company, Inc.

Common
Stock, $6.50 par value

New
York Stock Exchange

Appalachian
Power Company

None

Columbus
Southern Power Company

None

Indiana
Michigan Power Company

6%
Senior Notes, Series D, Due 2032

New
York Stock Exchange

Ohio
Power Company

None

Public
Service Company of Oklahoma

6%
Senior Notes, Series B, Due 2032

New
York Stock Exchange

Southwestern
Electric Power Company

None

Securities
registered pursuant to Section 12(g) of the Act:

Registrant

Title of each class

American
Electric Power Company, Inc.

None

Appalachian
Power Company

4.50%
Cumulative Preferred Stock, Voting, no par value

Columbus
Southern Power Company

None

Indiana
Michigan Power Company

None

Ohio
Power Company

4.50%
Cumulative Preferred Stock, Voting, $100 par value

Public
Service Company of Oklahoma

None

Southwestern
Electric Power Company

4.28%
Cumulative Preferred Stock, Voting, $100 par value

4.65%
Cumulative Preferred Stock, Voting, $100 par value

5.00%
Cumulative Preferred Stock, Voting, $100 par
value

Aggregate market value of
voting and non-voting common equity held by non-affiliates of the
registrantsas of
June 30, 2008, the last trading date of the registrants’ most recently
completed second fiscal quarter

Number
of shares of common stock outstanding of the registrants at

December
31, 2008

American
Electric Power Company, Inc.

$16,336,246,629

406,071,256

($6.50
par value)

Appalachian
Power Company

None

13,499,500

(no
par value)

Columbus
Southern Power Company

None

16,410,426

(no
par value)

Indiana
Michigan Power Company

None

1,400,000

(no
par value)

Ohio
Power Company

None

27,952,473

(no
par value)

Public
Service Company of Oklahoma

None

9,013,000

($15
par value)

Southwestern
Electric Power Company

None

7,536,640

($18
par
value)

Note
On Market Value Of Common Equity Held By Non-Affiliates

American
Electric Power Company, Inc. owns all of the common stock of Appalachian
Power Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company (see Item 12 herein).

Documents
Incorporated By Reference

Description

Part
of Form 10-K

Into
Which Document Is Incorporated

Portions
of Annual Reports of the following companies for

the
fiscal year ended December 31, 2008:

Part
II

American Electric Power Company,
Inc.

Appalachian Power
Company

Columbus Southern Power
Company

Indiana Michigan Power
Company

Ohio Power
Company

Public Service Company of
Oklahoma

Southwestern Electric Power
Company

Portions
of Proxy Statement of American Electric Power Company, Inc. for 2009
Annual Meeting of Shareholders.

Part
III

Portions
of Information Statements of the following companies for 2009 Annual
Meeting of Shareholders:

Part
III

Appalachian Power
Company

Ohio Power
Company

Public Service Company of
Oklahoma

Southwestern Electric Power
Company

This
combined Form 10-K is separately filed by American Electric Power Company, Inc.,
Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan
Power Company, Ohio Power Company, Public Service Company of Oklahoma and
Southwestern Electric Power Company. Information contained herein
relating to any individual registrant is filed by such registrant on its own
behalf. Except for American Electric Power Company, Inc., each registrant makes
no representation as to information relating to the other
registrants.

You
can access financial and other information at AEP’s website, including AEP’s
Principles of Business Conduct (which also serves as a code of ethics applicable
to Item 10 of this Form 10-K), certain committee charters and Principles of
Corporate Governance. The address is www.AEP.com. AEP makes
available, free of charge on its website, copies of its annual report on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments
to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the
Securities Exchange Act of 1934 as soon as reasonably practicable after filing
such material electronically or otherwise furnishing it to the
SEC.

The
Donald C. Cook Nuclear Plant (2,143 MW), owned by I&M, and located
near Bridgman, Michigan

CSPCo

Columbus
Southern Power Company, a public utility subsidiary of
AEP

CSW

Central
and South West Corporation, a public utility holding company that merged
with AEP in June 2000.

CSW
Operating Agreement

Agreement,
dated January 1, 1997, as amended, originally by and among PSO, SWEPCo,
TCC and TNC, currently by and between PSO and SWEPCO governing generating
capacity allocation. AEPSC acts as the agent for the
parties.

DOE

United
States Department of Energy

Dow

The
Dow Chemical Company, and its affiliates collectively, unaffiliated
companies

DP&L

The
Dayton Power and Light Company, an unaffiliated utility
company

Duke
Carolina

Duke
Energy Carolinas, LLC

Duke
Indiana

Duke
Energy Indiana, Inc.

Duke
Ohio

Duke
Energy Ohio, Inc.

EMF

Electric
and Magnetic Fields

EPA

United
States Environmental Protection Agency

EPACT

The
Energy Policy Act of 2005

ERCOT

Electric
Reliability Council of Texas

ESP

Electric
Security Plans, filed with the PUCO, pursuant to the Ohio
Amendments

ETEC

East
Texas Electric Cooperative

FERC

Federal
Energy Regulatory Commission

Fitch

Fitch
Ratings, Inc.

FPA

Federal
Power Act

I&M

Indiana
Michigan Power Company, a public utility subsidiary of
AEP

IGCC

Integrated
Gasification Combined Cycle

Interconnection
Agreement

Agreement,
dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo
and OPCo, defining the sharing of costs and benefits associated with their
respective generating plants

IURC

Indiana
Utility Regulatory Commission

KPCo

Kentucky
Power Company, a public utility subsidiary of AEP

KPSC

Kentucky
Public Service Commission

Lawrenceburg
Plant

A
1,146 MW gas-fired unit owned by AEGCo and located near Lawrenceburg,
Indiana

LLWPA

Low-Level
Waste Policy Act of 1980

LPSC

Louisiana
Public Service Commission

MISO

Midwest
Independent Transmission System Operator

Moody’s

Moody’s
Investors Service, Inc.

MW

Megawatt

NOx

Nitrogen
oxide

NPC

National
Power Cooperatives, Inc., an unaffiliated corporation

NRC

Nuclear
Regulatory Commission

OASIS

Open
Access Same-time Information System

OATT

Open
Access Transmission Tariff, filed with FERC

OCC

Corporation
Commission of the State of Oklahoma

Ohio
Act

Ohio
electric restructuring legislation

Ohio
Amendments

Amendments
to the Ohio Act adopted in April 2008 which require electric utilities to
adjust their rates by filing an ESP with the PUCO

OPCo

Ohio
Power Company, a public utility subsidiary of AEP

OVEC

Ohio
Valley Electric Corporation, an electric utility company in which AEP and
CSPCo together own a 43.47% equity interest

PJM

PJM
Interconnection, L.L.C., a regional transmission
organization

PSO

Public
Service Company of Oklahoma, a public utility subsidiary of
AEP

PUCO

Public
Utilities Commission of Ohio

PUCT

Public
Utility Commission of Texas

RCRA

Resource
Conservation and Recovery Act of 1976, as amended

REP

Texas
retail electricity provider

Rockport
Plant

A
generating plant owned and partly leased by AEGCo and I&M (two 1,300
MW, coal-fired) located near Rockport, Indiana

ROE

Return
on Equity

RTO

Regional
Transmission Organization

SEC

Securities
and Exchange Commission

S&P

Standard
& Poor’s Ratings Service

SO2

Sulfur
dioxide

SPP

Southwest
Power Pool

SWEPCo

Southwestern
Electric Power Company, a public utility subsidiary of
AEP

TCA

Transmission
Coordination Agreement dated January 1, 1997 by and among, PSO, SWEPCo,
TCC, TNC and AEPSC, which allocated costs and benefits through September
2005 in connection with the operation of the transmission assets of the
four public utility subsidiaries

TCC

AEP
Texas Central Company, formerly Central Power and Light Company, a public
utility subsidiary of AEP

TEA

Transmission
Equalization Agreement dated April 1, 1984 by and among APCo, CSPCo,
I&M, KPCo and OPCo, which allocates costs and benefits in connection
with the operation of transmission assets

Texas
Act

Texas
electric restructuring legislation

TNC

AEP
Texas North Company, formerly West Texas Utilities Company, a public
utility subsidiary of AEP

Tractebel

Tractebel
Energy Marketing, Inc.

TVA

Tennessee
Valley Authority

VSCC

Virginia
State Corporation Commission

WPCo

Wheeling
Power Company, a public utility subsidiary of AEP

WVPSC

West
Virginia Public Service Commission

FORWARD-LOOKING
INFORMATION

This
report made by the registrants contains forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of
1934. Although the registrants believe that their expectations are
based on reasonable assumptions, any such statements may be influenced by
factors that could cause actual outcomes and results to be materially different
from those projected. Among the factors that could cause actual
results to differ materially from those in the forward-looking statements
are:

·

The
economic climate and growth in, or contraction within, our service
territory and changes in market demand and demographic
patterns.

·

Inflationary
or deflationary interest rate trends.

·

Volatility
in the financial markets, particularly developments affecting the
availability of capital on reasonable terms and developments impairing our
ability to finance new capital projects and refinance existing debt at
attractive rates.

·

The
availability and cost of funds to finance working capital and capital
needs, particularly during periods when the time lag between incurring
costs and recovery is long and the costs are material.

·

Electric
load and customer growth.

·

Weather
conditions, including storms.

·

Available
sources and costs of, and transportation for, fuels and the
creditworthiness and performance of fuel suppliers and
transporters.

·

Availability
of generating capacity and the performance of our generating plants
including our ability to restore Cook Plant Unit 1 in a timely
manner.

·

Our
ability to recover regulatory assets and stranded costs in connection with
deregulation.

·

Our
ability to recover increases in fuel and other energy costs through
regulated or competitive electric rates.

·

Our
ability to build or acquire generating capacity and transmission line
facilities (including our ability to obtain any necessary regulatory or
siting approvals and permits) when needed at acceptable prices and terms
and to recover those costs (including the costs of projects that are
cancelled) through applicable rate cases or competitive
rates.

·

New
legislation, litigation and government regulation including requirements
for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or
particulate matter and other substances.

·

Timing
and resolution of pending and future rate cases, negotiations and other
regulatory decisions (including rate or other recovery of new investments
in generation, distribution and transmission service and environmental
compliance).

·

Resolution
of litigation (including disputes arising from the bankruptcy of Enron
Corp. and related matters).

·

Our
ability to constrain operation and maintenance costs.

·

Our
ability to develop and execute a strategy based on a view regarding prices
of electricity, natural gas and other energy-related
commodities.

·

Changes
in the creditworthiness of the counterparties with whom we have
contractual arrangements, including participants in the energy trading
market.

·

Actions
of rating agencies, including changes in the ratings of
debt.

·

Volatility
and changes in markets for electricity, natural gas, coal, nuclear fuel
and other energy-related commodities.

·

Changes
in utility regulation, including the implementation of the recently passed
utility law in Ohio and the allocation of costs within RTOs, including PJM
and SPP.

The
impact of volatility in the capital markets on the value of the
investments held by our pension, other postretirement benefit plans and
nuclear decommissioning trust and the impact on future funding
requirements.

·

Prices
for power that we generate and sell at wholesale.

·

Changes
in technology, particularly with respect to new, developing or alternative
sources of generation.

·

Other
risks and unforeseen events, including wars, the effects of terrorism
(including increased security costs), embargoes and other catastrophic
events.

The
registrants expressly disclaim any obligation to update any
forward-looking information.

PART
I

ITEM
1. BUSINESS

GENERAL

OVERVIEW
AND DESCRIPTION OF SUBSIDIARIES

AEP was
incorporated under the laws of the State of New York in 1906 and reorganized in
1925. It is a public utility holding company that owns, directly or indirectly,
all of the outstanding common stock of its public utility subsidiaries and
varying percentages of other subsidiaries.

The
service areas of AEP’s public utility subsidiaries cover portions of the states
of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee,
Texas, Virginia and West Virginia. The generating and transmission facilities of
AEP’s public utility subsidiaries are interconnected and their operations are
coordinated. Transmission networks are interconnected with extensive
distribution facilities in the territories served. The public utility
subsidiaries of AEP have traditionally provided electric service, consisting of
generation, transmission and distribution, on an integrated basis to their
retail customers. Restructuring legislation in Michigan, Ohio, the ERCOT area of
Texas and, through 2008, Virginia has caused AEP public utility subsidiaries in
those states to unbundle previously integrated regulated rates for their retail
customers. Virginia has returned to integrated regulated
rates.

The AEP
System is an integrated electric utility system. As a result, the member
companies of the AEP System have contractual, financial and other business
relationships with the other member companies, such as participation in the AEP
System savings and retirement plans and tax returns, sales of electricity and
transportation and handling of fuel. The companies of the AEP System also obtain
certain accounting, administrative, information systems, engineering, financial,
legal, maintenance and other services at cost from a common provider,
AEPSC.

At
December 31, 2008, the subsidiaries of AEP had a total of 21,912 employees.
Because it is a holding company rather than an operating company, AEP has no
employees. The public utility subsidiaries of AEP are:

APCo(organized in Virginia
in 1926) is engaged in the generation, transmission and distribution of electric
power to approximately 962,000 retail customers in the southwestern portion of
Virginia and southern West Virginia, and in supplying and marketing electric
power at wholesale to other electric utility companies, municipalities and other
market participants. At December 31, 2008, APCo and its wholly owned
subsidiaries had 2,575 employees. Among the principal industries
served by APCo are coal mining, primary metals, chemicals and textile mill
products. In addition to its AEP System interconnections, APCo is interconnected
with the following unaffiliated utility companies: Carolina Power & Light
Company, Duke Carolina and Virginia Electric and Power Company. APCo has several
points of interconnection with TVA and has entered into agreements with TVA
under which APCo and TVA interchange and transfer electric power over portions
of their respective systems. APCo is a member of PJM.

CSPCo(organized in Ohio in
1937, the earliest direct predecessor company having been organized in 1883) is
engaged in the generation, transmission and distribution of electric power to
approximately 749,000 retail customers in Ohio, and in supplying and marketing
electric power at wholesale to other electric utilities, municipalities and
other market participants. At December 31, 2008, CSPCo had 1,323 employees.
CSPCo’s service area is comprised of two areas in Ohio, which include portions
of twenty-five counties. One area includes the City of Columbus and the other is
a predominantly rural area in south central Ohio. Among the principal industries
served are food processing, chemicals, primary metals, electronic machinery and
paper products. In addition to its AEP System interconnections, CSPCo is
interconnected with the following unaffiliated utility companies: Duke Ohio,
DP&L and Ohio Edison Company. CSPCo is a member of
PJM.

I&M(organized in Indiana
in 1925) is engaged in the generation, transmission and distribution of electric
power to approximately 582,000 retail customers in northern and eastern Indiana
and southwestern Michigan, and in supplying and marketing electric power at
wholesale to other electric utility companies, rural electric cooperatives,
municipalities and other market participants. At December 31, 2008,
I&M had 2,879 employees. Among the principal industries served are primary
metals, transportation equipment, electrical and electronic machinery,
fabricated metal products, rubber and miscellaneous plastic products and
chemicals and allied products. Since 1975, I&M has leased and operated the
assets of the municipal system of the City of Fort Wayne, Indiana. This lease
currently extends through February 2010. In addition to its AEP
System interconnections, I&M is interconnected with the following
unaffiliated utility companies: Central Illinois Public Service Company, Duke
Ohio, Commonwealth Edison Company, Consumers Energy Company, Illinois Power
Company, Indianapolis Power & Light Company, Louisville Gas and Electric
Company, Northern Indiana Public Service Company, Duke Indiana and Richmond
Power & Light Company. I&M is a member of PJM.

KPCo(organized in Kentucky
in 1919) is engaged in the generation, transmission and distribution of electric
power to approximately 176,000 retail customers in an area in eastern Kentucky,
and in supplying and marketing electric power at wholesale to other electric
utility companies, municipalities and other market participants. At
December 31, 2008, KPCo had 480 employees. In addition to its AEP System
interconnections, KPCo is interconnected with the following unaffiliated utility
companies: Kentucky Utilities Company and East Kentucky Power Cooperative Inc.
KPCo is also interconnected with TVA. KPCo is a member of
PJM.

Kingsport Power
Company(organized in Virginia
in 1917) provides electric service to approximately 47,000 retail customers in
Kingsport and eight neighboring communities in northeastern Tennessee. Kingsport
Power Company does not own any generating facilities and is a member of PJM. It
purchases electric power from APCo for distribution to its customers. At
December 31, 2008, Kingsport Power Company had 58 employees.

OPCo(organized in Ohio in
1907 and re-incorporated in 1924) is engaged in the generation, transmission and
distribution of electric power to approximately 712,000 retail customers in the
northwestern, east central, eastern and southern sections of Ohio, and in
supplying and marketing electric power at wholesale to other electric utility
companies, municipalities and other market participants. At December 31, 2008,
OPCo had 2,434 employees. Among the principal industries served by OPCo are
primary metals, rubber and plastic products, stone, clay, glass and concrete
products, petroleum refining and chemicals. In addition to its AEP System
interconnections, OPCo is interconnected with the following unaffiliated utility
companies: Duke Ohio, The Cleveland Electric Illuminating Company, DP&L,
Duquesne Light Company, Kentucky Utilities Company, Monongahela Power Company,
Ohio Edison Company, The Toledo Edison Company and West Penn Power
Company. OPCo is a member of PJM.

PSO(organized in Oklahoma
in 1913) is engaged in the generation, transmission and distribution of electric
power to approximately 527,000 retail customers in eastern and southwestern
Oklahoma, and in supplying and marketing electric power at wholesale to other
electric utility companies, municipalities, rural electric cooperatives and
other market participants. At December 31, 2008, PSO had 1,279 employees. Among
the principal industries served by PSO are natural gas and oil production, oil
refining, steel processing, aircraft maintenance, paper manufacturing and timber
products, glass, chemicals, cement, plastics, aerospace manufacturing,
telecommunications, and rubber goods. In addition to its AEP System
interconnections, PSO is interconnected with Empire District Electric Company,
Oklahoma Gas and Electric Company, Southwestern Public Service Company and
Westar Energy, Inc. PSO is a member of SPP.

SWEPCo(organized in Delaware
in 1912) is engaged in the generation, transmission and distribution of electric
power to approximately 471,000 retail customers in northeastern Texas,
northwestern Louisiana and western Arkansas, and in supplying and marketing
electric power at wholesale to other electric utility companies, municipalities,
rural electric cooperatives and other market participants. At December 31, 2008,
SWEPCo had 1,641 employees. Among the principal industries served by SWEPCo are
natural gas and oil production, petroleum refining, manufacturing of pulp and
paper, chemicals, food processing, and metal refining. The territory served by
SWEPCo also includes several military installations, colleges, and universities.
SWEPCO also owns and operates a lignite coal mining operation. In
addition to its AEP System interconnections, SWEPCo is interconnected with CLECO
Corp., Empire District Electric Co., Entergy Corp. and Oklahoma Gas &
Electric Co. SWEPCo is a member of SPP.

TCC
(organized in Texas in 1945) is engaged in the transmission and
distribution of electric power to approximately 761,000 retail customers through
REPs in southern Texas. Under the Texas Act, TCC has completed the final stage
of exiting the generation business and has sold all of its generation
assets. At December 31, 2008, TCC had 1,201 employees. Among the
principal industries served by TCC are oil and gas extraction, food processing,
apparel, metal refining, chemical and petroleum refining, plastics, and
machinery equipment. In addition to its AEP System interconnections, TCC is a
member of ERCOT.

TNC(organized in Texas in
1927) is engaged in the transmission and distribution of electric power to
approximately 185,000 retail customers through REPs in west and central Texas.
TNC’s remaining generating capacity that is not deactivated has been transferred
to an affiliate at TNC’s cost pursuant to an agreement effective through
2027. At December 31, 2008, TNC had 370 employees. Among the
principal industries served by TNC are agriculture and the manufacturing or
processing of cotton seed products, oil products, precision and consumer metal
products, meat products and gypsum products. The territory served by TNC also
includes several military installations and correctional facilities. In addition
to its AEP System interconnections, TNC is a member of ERCOT.

WPCo
(organized in West Virginia in 1883 and reincorporated in 1911) provides
electric service to approximately 41,000 retail customers in northern West
Virginia. WPCo does not own any generating facilities. WPCo is a
member of PJM. It purchases electric power from OPCo for distribution to its
customers. At December 31, 2008, WPCo had 62 employees.

AEGCo(organized in Ohio in
1982) is an electric generating company. AEGCo sells power at wholesale to
I&M, CSPCo and KPCo. AEGCo has no employees.

SERVICE COMPANY
SUBSIDIARY

AEP also
owns a service company subsidiary, AEPSC. AEPSC provides accounting,
administrative, information systems, engineering, financial, legal, maintenance
and other services at cost to the AEP affiliated companies. The
executive officers of AEP and certain of its public utility subsidiaries are
employees of AEPSC. At December 31, 2008, AEPSC had 6,351
employees.

CLASSES
OF SERVICE

The
principal classes of service from which AEP and the registrant subsidiaries of
AEP derive revenues and the amount of such revenues during the year ended
December 31, 2008 are as follows:

Description

AEP System(a)

APCo

CSPCo

I&M

(in
thousands)

UTILITY
OPERATIONS:

Retail
Sales

Residential
Sales

$4,267,000

$
891,159

$
720,761

$427,877

Commercial
Sales

3,116,000

426,277

684,277

333,575

Industrial
Sales

2,954,000

601,166

328,010

364,670

PJM
Net Charges

(214,000)

(72,898)

(40,249)

(38,782)

Provision
for Rate Refund

(105,000)

(52,910)

(30,359)

(33,279)

Other
Retail Sales

210,000

55,359

5,873

6,044

Total
Retail

10,228,000

1,848,153

1,668,313

1,060,105

Wholesale

Off-System
Sales

2,690,000

720,574

430,093

675,205

Transmission

58,000

(52,740)

(30,419)

(16,235)

Total
Wholesale

2,748,000

667,834

399,674

658,970

Other
Electric Revenues

244,000

26,235

11,623

8,694

Other
Operating Revenues

106,000

18,199

5,542

19,102

Sales
To Affiliates

-

328,735

122,949

419,488

Total
Utility Operating Revenues

13,326,000

2,889,156

2,208,101

2,166,359

OTHER

1,114,000

-

-

-

TOTAL
REVENUES

$14,440,000

$
2,889,156

$
2,208,101

$2,166,359

Description

OPCo

PSO

SWEPCo

(in
thousands)

UTILITY
OPERATIONS:

Retail
Sales

Residential
Sales

$
602,770

$
557,195

$440,826

Commercial
Sales

402,149

407,052

382,984

Industrial
Sales

694,890

357,884

280,082

PJM
Net Charges

(47,705)

-

-

Provision
for Rate Refund

(42,435)

13,811

21,417

Other
Retail Sales

9,439

99,158

7,906

Total
Retail

1,619,108

1,435,100

1,133,215

Wholesale

Off-System
Sales

511,961

62,980

267,689

Transmission

(38,529)

27,234

39,966

Total
Wholesale

473,432

90,214

307,655

Other
Electric Revenues

24,257

24,176

17,157

Other
Operating Revenues

18,937

4,853

45,893

Sales
to Affiliates

961,200

101,602

50,842

Total
Utility Operating Revenues

3,096,934

1,655,945

1,554,762

OTHER

-

-

-

TOTAL
REVENUES

$
3,096,934

$
1,655,945

$1,554,762

(a)

Includes
revenues of other subsidiaries not shown. Intercompany transactions have
been eliminated for the year ended December 31, 2008.

FINANCING

General

Companies
within the AEP System generally use short-term debt to finance working capital
needs. Short-term debt is also used to finance acquisitions,
construction and redemption or repurchase of outstanding securities until such
needs can be financed with long-term debt. In recent history, short-term funding
needs have been provided for by cash on hand, borrowing under AEP's revolving
credit agreements and AEP’s commercial paper program. Funds are
made available to subsidiaries under the AEP corporate borrowing program.
Certain public utility subsidiaries of AEP also sell accounts receivable to
provide liquidity. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2008 Annual
Reports, under the heading entitled Financial Condition for
additional information concerning short-term funding and our access to bank
lines of credit, commercial paper and capital markets.

AEP’s
revolving credit agreements (which backstop the commercial paper program)
include covenants and events of default typical for this type of facility,
including a maximum debt/capital test and a $50 million cross-acceleration
provision. At December 31, 2008, AEP was in compliance with its debt covenants.
With the exception of a voluntary bankruptcy or insolvency, any event of default
has either or both a cure period or notice requirement before termination of the
agreements. A voluntary bankruptcy or insolvency of AEP would be considered an
immediate termination event. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2008 Annual
Reports, under the heading entitled Financial Condition for
additional information with respect to AEP’s credit agreements.

AEP’s
subsidiaries have also utilized, and expect to continue to utilize, additional
financing arrangements, such as leasing arrangements, including the leasing of
coal transportation equipment and facilities.

Credit
Ratings

The
credit ratings of AEP and its registrant subsidiaries as of February 18, 2009
are set forth below. Over the first two months of 2009, Moody’s
placed the senior unsecured debt rating of AEP on negative outlook, the senior
unsecured debt rating of OPCo, SWEPCo, TCC and TNC on review for possible
downgrade and changed the outlook of APCo from negative to stable. In
February 2008 Fitch downgraded the senior unsecured debt rating of PSO to BBB+
with stable outlook. Fitch placed the senior unsecured debt rating of
APCo and TCC on negative outlook in May 2008 and February 2009,
respectively. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2008 Annual
Reports, under the heading entitled Financial Condition for
additional information with respect to the credit ratings of the
registrants.

AEP’s
subsidiaries are currently subject to regulation by federal, state and local
authorities with regard to air and water-quality control and other environmental
matters, and are subject to zoning and other regulation by local authorities.
The environmental issues that are potentially material to the AEP system
include:

·

Global
climate change and legislative and regulatory responses to it, including
limitations on CO2
emissions. See Management’s Financial
Discussion and Analysis of Results of Operations under the headings
entitled Environmental
Matters – Potential Regulation ofCO2 and Other GHG
Emissions.

·

The
CAA and CAAA and state laws and regulations (including State
Implementation Plans) that require compliance, obtaining permits and
reporting as to air emissions. See Management’s Financial
Discussion and Analysis of Results of Operations under the headings
entitled Environmental
Matters -Clean
Air Act Requirements and Estimated Air Quality
Environmental Investments.

·

Litigation
with the federal and/or certain state governments and certain special
interest groups regarding regulated air emissions and/or whether emissions
from coal-fired generating plants cause or contribute to global climate
changes. See Management’s Financial
Discussion and Analysis of Results of Operations under the heading
entitled Litigation
- Environmental
Litigation and Note 6 to the consolidated financial statements
entitled Commitments,
Guarantees and Contingencies, included in the 2008 Annual Reports,
for further information.

·

Rules
issued by the EPA and certain states that require substantial reductions
in SO2 and
NOx
emissions and future rules for mercury emission reductions, which have
compliance dates that take effect periodically through as late as 2018.
AEP is installing (and has installed) emission control technology and is
taking other measures to comply with required reductions. See Management’s Financial
Discussion and Analysis of Results of Operations under the headings
entitled Environmental
Matters - Clean Air Act Requirements and Estimated Air Quality
Environmental Investments included in the 2008 Annual Reports for
further information.

·

CERCLA,
which imposes costs for environmental remediation upon owners and previous
owners of sites, as well as transporters and generators of hazardous
material disposed of at such sites. See Note 6 to the
consolidated financial statements entitled Commitments, Guarantees and
Contingencies, included in the 2008 Annual Reports, under the
heading entitled The
Comprehensive Environmental Response Compensation and Liability Act
(Superfund) and State
Remediation for further information.

·

The
Federal Clean Water Act, which prohibits the discharge of pollutants into
waters of the United States except pursuant to appropriate
permits, and regulates systems that withdraw surface water for use in
our power plants. See Management’s Financial
Discussion and Analysis of Results of Operations, included in the
2008 Annual Reports, under the heading entitled Environmental Matters -Clean Water Act
Regulations for additional
information.

·

Solid
and hazardous waste laws and regulations, which govern the management and
disposal of certain wastes, and other laws governing the use of ash
impoundments, including containment dams. The majority of solid waste
created from the combustion of coal and fossil fuels is fly ash and other
coal combustion byproducts, which the EPA has determined are not hazardous
waste subject to RCRA.

In
addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions. See Management’s Financial Discussion
and Analysis of Results of Operations under the heading entitled Environmental Matters,
included in the 2008 Annual Reports,for further information
with respect to environmental issues.

While we
expect to recover our expenditures for pollution control technologies,
replacement generation and associated operating costs from customers through
regulated rates (in regulated jurisdictions) or market prices, without such
recovery those costs could adversely affect future results of operations and
cash flows, and possibly financial condition. The cost of complying
with applicable environmental laws, regulations and rules is expected to be
material to the AEP System. See Management’s Financial Discussion
and Analysis of Results of Operations under the heading entitled Environmental Matters and
Note 6 to the consolidated financial statements entitled Commitments, Guarantees and
Contingencies, included in the 2008 Annual Reports, for more information
regarding environmental matters.

Environmental
Investments

Investments
related to improving AEP System plants’ environmental performance and compliance
with air and water quality standards during 2006, 2007 and 2008 and the current
estimates for 2009, 2010 and 2011 are shown below, in each case excluding AFUDC
or capitalized interest. AEP expects to make substantial investments in addition
to the amounts set forth below in future years in connection with the
modification and addition of facilities at generating plants for environmental
quality controls. Such future investments are needed in order to
comply with air and water quality standards which have been adopted and have
deadlines for compliance after 2010 or have been proposed and may be
adopted. Future investments could be significantly greater if
emissions reduction requirements are accelerated or otherwise become more
onerous or if CO2 becomes
regulated. See Management’s
Financial Discussion and Analysis of Results of Operations under the
heading entitled Environmental
Matters andNote 6 to the
consolidated financial statements, entitled Commitments, Guarantees and
Contingencies, included in the 2008 Annual Reports, for more information
regarding environmental expenditures in general.

Historical
and Projected Environmental Investments

2006

2007

2008

2009

2010

2011

Actual

Actual

Actual

Estimate

Estimate

Estimate

(in
thousands)

Total
AEP System*

$1,366,200

$994,100

$886,800

$436,100

$581,900

$892,400

APCo

532,800

351,900

361,200

99,400

183,900

71,400

CSPCo

138,900

130,000

162,800

69,700

54,600

57,900

I&M

23,200

9,300

22,400

40,600

3,600

2,000

OPCo

660,800

481,700

311,800

179,800

49,200

116,400

PSO

500

1,500

5,000

1,000

22,200

265,100

SWEPCo

21,000

14,300

12,000

22,300

170,400

243,600

*
Includes expenditures of the subsidiaries shown and other subsidiaries not
shown. The figures reflect construction expenditures, not investments in
subsidiary companies. Excludes discontinued
operations.

Electric
and Magnetic Fields

EMF are
found everywhere there is electricity. Electric fields are created by the
presence of electric charges. Magnetic fields are produced by the flow of those
charges. This means that EMF are created by electricity flowing in transmission
and distribution lines, electrical equipment, household wiring, and
appliances. A number of studies in the past have examined the
possibility of adverse health effects from EMF. While some of the
epidemiological studies have indicated some association between exposure to EMF
and health effects, none has produced any conclusive evidence that EMF does or
does not cause adverse health effects.

Management cannot predict the ultimate
impact of the question of EMF exposure and adverse health effects. If further
research shows that EMF exposure contributes to increased risk of cancer or
other health problems, or if the courts conclude that EMF exposure harms
individuals and that utilities are liable for damages, or if states limit the
strength of magnetic fields to such a level that the current electricity
delivery system must be significantly changed, then the results of operations
and financial condition of AEP and its operating subsidiaries could be
materially adversely affected unless these costs can be recovered from
customers.

UTILITY
OPERATIONS

GENERAL

Utility
operations constitute most of AEP’s business operations. Utility
operations include (i) the generation, transmission and distribution of electric
power to retail customers and (ii) the supplying and marketing of electric power
at wholesale (through the electric generation function) to other electric
utility companies, municipalities and other market
participants. AEPSC, as agent for AEP’s public utility subsidiaries,
performs marketing, generation dispatch, fuel procurement and power-related risk
management and trading activities.

ELECTRIC
GENERATION

Facilities

AEP’s
public utility subsidiaries own or lease approximately 37,000 MW of domestic
generation. See Item 2 —
Properties for more information regarding AEP’s generation
capacity.

AEP
Power Pool and CSW Operating Agreement

APCo,
CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement
defining how they share the costs and benefits associated with their generating
plants. This sharing is based upon each company’s “member-load-ratio.” The
Interconnection Agreement has been approved by the FERC. The
member-load-ratio is calculated monthly by dividing such company’s highest
monthly peak demand for the last twelve months by the aggregate of the highest
monthly peak demand for the last twelve months for all AEP East companies. As of
December 31, 2008, the member-load-ratios were as follows:

Peak

Demand

(MW)

Member-Load

Ratio
(%)

APCo

7,848

33.2

CSPCo

4,406

18.6

I&M

4,264

18.0

KPCo

1,678

7.1

OPCo

5,458

23.1

Ohio’s
electric restructuring law, the Ohio Act, was enacted in 2001. To
comply with that law CSPCo and OPCo functionally separated their generation
business from their remaining operations. They remained functionally
separated through December 31, 2008 as authorized by their rate stabilization
plans approved by the PUCO. Pursuant to rules recently adopted by the
PUCO, CSPCo and OPCo expect to file corporate separation plans with
the PUCO. See Note 4 to the consolidated financial statements,
entitled Rate Matters,
included in the 2008 Annual Reports, for more information.

APCo,
CSPCo, I&M, KPCo and OPCo are parties to the AEP System Interim Allowance
Agreement (Allowance Agreement), which provides, among other things, for the
transfer of emission allowances associated with transactions under the
Interconnection Agreement. The following table shows the net
(credits) or charges allocated among the parties under the Interconnection
Agreement during the years ended December 31, 2006, 2007 and 2008:

2006

2007

2008

(in
thousands)

APCo

$319,500

$454,800

$575,300

CSPCo

281,700

173,000

233,200

I&M

(146,100)

(93,200)

(153,000)

KPCo

38,800

41,200

65,000

OPCo

(493,900)

(575,800)

(720,500)

PSO,
SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement
originally dated as of January 1, 1997 (CSW Operating Agreement), which has been
approved by the FERC. The CSW Operating Agreement requires these public utility
subsidiaries to maintain adequate annual planning reserve margins and requires
the subsidiaries that have capacity in excess of the required margins to make
such capacity available for sale to other public utility subsidiary parties as
capacity commitments. Parties are compensated for energy delivered to the
recipients based upon the deliverer’s incremental cost plus a portion of the
recipient’s savings realized by the purchaser that avoids the use of more costly
alternatives. Revenues and costs arising from third party sales in
their region are generally shared based on the amount of energy each west zone
public utility subsidiary contributes that is sold to third
parties. The separation of the generation business undertaken by TCC
and TNC to comply with the Texas Act has made their business operations
incompatible with the CSW Operating Agreement. As a result, with FERC
approval, these companies as of May 1, 2006, are no longer parties to, and no
longer supply generating capacity under, the CSW Operating
Agreement.

The
following table shows the net (credits) or charges allocated among the parties
under the CSW Operating Agreement during the years ended December 31, 2006, 2007
and 2008:

2006

2007

2008

(in
thousands)

PSO

$(15,300)

$(17,500)

$(57,000)

SWEPCo

9,900

16,800

59,900

TCC

0

0

0

TNC

5,400

700

(2,900)

Power
generated by or allocated or provided under the Interconnection Agreement or CSW
Operating Agreement to any public utility subsidiary is primarily sold to
customers by such public utility subsidiary at rates approved by the public
utility commission in the jurisdiction of sale. In Ohio and Virginia, such rates
are based on a statutory formula as Ohio considers continuing to transition to
the use of market rates for generation and as Virginia completes its final year
of transition before returning to a form of cost-based regulation. See Regulation — Rates under
Item 1, Utility
Operations.

Under
both the Interconnection Agreement and CSW Operating Agreement, power that is
not needed to serve the native load of our public utility subsidiaries is sold
in the wholesale market by AEPSC on behalf of those subsidiaries. See
Risk Management and
Trading, below,
for a discussion of the trading and marketing of such power.

AEP’s
System Integration Agreement provides for the integration and coordination of
AEP’s East companies, PSO and SWEPCO. This includes joint dispatch of generation
within the AEP System and the distribution, between the two zones, of costs and
benefits associated with the transfers of power between the two zones (including
sales to third parties and risk management and trading activities). It is
designed to function as an umbrella agreement in addition to the Interconnection
Agreement and the CSW Operating Agreement, each of which controls the
distribution of costs and benefits for activities within each
zone. Because TCC and TNC have exited the generation business, these
two companies are no longer parties to the System Integration
Agreement. In an order issued November 26, 2008, the FERC ruled that
AEP should reallocate pre-tax trading margins from off-system sales
between the AEP East Companies and the AEP West Companies during the period from
June 2000 to March 2006 governed by the previous system integration
agreement. See Note 4 to the consolidated financial statements,
entitled Rate Matters,
included in the 2008 Annual Reports under the heading entitled FERC Rate Matters for
additional information.

Risk
Management and Trading

As agent
for AEP’s public utility subsidiaries, AEPSC sells excess power into the market
and engages in power, natural gas, coal and emissions allowances risk management
and trading activities focused in regions in which AEP traditionally operates
and in adjacent regions. These activities primarily involve the purchase and
sale of electricity (and to a lesser extent, natural gas, coal and emissions
allowances) under physical forward contracts at fixed and variable prices. These
contracts include physical transactions, over-the-counter swaps and
exchange-traded futures and options. The majority of physical forward contracts
are typically settled by entering into offsetting contracts.These transactions are
executed with numerous counterparties or on exchanges. Counterparties and
exchanges may require cash or cash related instruments to be deposited on these
transactions as margin against open positions. As of December 31, 2008,
counterparties have posted approximately $29 million in cash, cash equivalents
or letters of credit with AEPSC for the benefit of AEP’s public utility
subsidiaries (while, as of that date, AEP’s public utility subsidiaries had
posted approximately $100 million with counterparties and
exchanges). Since open trading contracts are valued based on market
power prices, exposures change daily. See Management’s Financial Discussion
and Analysis of Results of Operations, included in the 2008 Annual
Reports, under the heading entitled Quantitative and Qualitative
Disclosures About Risk Management Activitiesfor additional
information.

Fuel
Supply

The
following table shows the sources of fuel used by the AEP System:

2006

2007

2008

Coal
and Lignite

85%

85%

86%

Natural
Gas

6%

6%

6%

Nuclear

9%

9%

8%

Hydroelectric
and other

<1%

<1%

<1%

Price
increases in one or more fuel sources relative to other fuels generally result
in increased use of other fuels.

Coal and
Lignite: AEP’s public utility
subsidiaries procure coal and lignite under a combination of purchasing
arrangements including long-term contracts, affiliate operations and spot
agreements with various producers and coal trading firms. The price
for most solid fuels has been increasing due to increased mining costs
(including labor, diesel fuel, mining equipment, implementation of new safety
regulations, and permitting difficulties) in addition to higher international
demand for eastern U.S. coals. To the extent practical, management
has responded to increases in the price of coal by rebalancing the coal used in
its generating facilities with products from different coal regions and sources
that have different heat and sulfur contents. This rebalancing is an
ongoing process that is expected to continue, significantly enabled by the
installation of scrubbers at a number of our generating facilities. Management
believes that AEP’s public utility subsidiaries will be able to secure and
transport coal and lignite of adequate quality and in adequate quantities to
operate their coal and lignite-fired units. Through subsidiaries, AEP
owns, leases or controls more than 9,000 railcars, 726 barges, 18 towboats and a
coal handling terminal with 18 million tons of annual capacity to move and store
coal for use in our generating facilities. See AEP River Operations
for a discussion of AEP’s for-profit coal and other dry-bulk commodity
transportation operations that are not part of AEP’s Utility Operations
segment.

The price
of coal in the various spot markets remains volatile. During the
first half of 2008, spot market prices for coal generally rose; in the second
half of 2008, spot market prices for coal generally decreased. Most
of the coal we purchase is procured through long-term contracts. The
prices we pay under these contracts is usually lower than the spot market price
of coal. As these long-term contracts expire they are replaced with
new agreements, often at higher prices. The price we paid for coal in
2008 rose from the prior year as a result of this. We expect this
trend to continue in 2009.

The
following table shows the amount of coal and lignite delivered to the AEP System
plants during the past three years and the average delivered price of coal
purchased by AEP System companies:

2006

2007

2008

Total
coal delivered to AEP System plants (thousands of tons)

76,045

72,644

77,054

Average
price per ton of purchased coal

$35.27

$36.65

$47.14

The coal
supplies at AEP System plants vary from time to time depending on various
factors, including, but not limited to, demand for electric power, unit outages,
transportation infrastructure limitations, space limitations, plant coal
consumption rates, availability of acceptable coals, labor issues and weather
conditions which may interrupt production or deliveries. At December 31, 2008,
the System’s coal inventory was approximately 32 days of normal
usage. This estimate assumes that the total supply would be utilized
through the operation of plants that use coal most efficiently.

In cases
of emergency or shortage, AEP has developed programs to conserve coal supplies
at its plants. Such programs have been filed and reviewed with federally
approved electric reliability organizations. In some cases, the
relevant state regulatory agency has prescribed actions to be taken under
specified circumstances by System companies, subject to the jurisdiction of such
agency.

The FERC
has adopted regulations relating, among other things, to the circumstances under
which, in the event of fuel emergencies or shortages, it might order electric
utilities to generate and transmit electric power to other regions or systems
experiencing fuel shortages, and to ratemaking principles by which such electric
utilities would be compensated. In addition, the federal government is
authorized, under prescribed conditions, to reallocate coal and to require the
transportation thereof, for the use at power plants or major fuel-burning
installations experiencing fuel shortages.

Natural
Gas: Through its
public utility subsidiaries, AEP consumed nearly 103 billion cubic feet of
natural gas during 2008 for generating power. This represents a slight decrease
from 2007 due to reduced demand in AEP’s eastern jurisdictions. Many
of the natural gas-fired power plants are connected to at least two pipelines,
which allows greater access to competitive supplies and improves delivery
reliability. A portfolio of long-term, monthly, seasonal firm and daily peaking
purchase and transportation agreements (that are entered into on a competitive
basis and based on market prices) supplies natural gas requirements for each
plant, as needed.

Nuclear:
I&M
has made commitments to meet the current nuclear fuel requirements of the Cook
Plant. I&M has made and will make purchases of uranium in various forms in
the spot, short-term, and mid-term markets. I&M also continues to lease a
portion of its nuclear fuel requirements.

For
purposes of the storage of high-level radioactive waste in the form of spent
nuclear fuel, I&M completed modifications to its spent nuclear fuel storage
pool more than 10 years ago. I&M anticipates that the Cook Plant has
sufficient storage capacity for its spent nuclear fuel to permit normal
operations through 2013. I&M has entered into an agreement to
provide for onsite dry cask storage. Initial loading of spent nuclear
fuel into the dry casks is tentatively scheduled to begin in 2011, which should
permit normal operations through 2037, its current licensing
period.

Nuclear
Waste and Decommissioning

As the
owner of the Cook Plant, I&M has a significant future financial commitment
to dispose of spent nuclear fuel and decommission and decontaminate the plant
safely. The cost to decommission a nuclear plant is affected by NRC regulations
and the spent nuclear fuel disposal program. In 2006, when the most
recent study was done, the estimated cost of decommissioning and disposal of
low-level radioactive waste for the Cook Plant ranged from $733 million to $1.3
billion in 2006 non-discounted dollars. At December 31, 2008, the
total decommissioning trust fund balance for the Cook Plant was $959
million. The balance of funds available to decommission Cook Plant
will differ based on contributions and investment returns. The
ultimate cost of retiring the Cook Plant may be materially different from
estimates and funding targets as a result of the:

·

Type
of decommissioning plan selected;

·

Escalation
of various cost elements (including, but not limited to, general inflation
and the cost of energy);

·

Further
development of regulatory requirements governing
decommissioning;

·

Technology
available at the time of decommissioning differing significantly from that
assumed in studies;

·

Availability
of nuclear waste disposal facilities;
and

·

Availability
of a DOE facility for permanent storage of spent nuclear
fuel.

Accordingly,
management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant will not be significantly different than current
projections. We will seek recovery from customers through our
regulated rates if actual decommissioning costs exceed our
projections. See Note 9 to the consolidated financial statements,
entitled Nuclear,
included in the 2008 Annual Reports, for information with respect to nuclear
waste and decommissioning.

Low-Level
Radioactive Waste: The LLWPA mandates that the
responsibility for the disposal of low-level radioactive waste rests with the
individual states. Low-level radioactive waste consists largely of ordinary
refuse and other items that have come in contact with radioactive materials.
Michigan does not currently have a disposal site for such waste available.
I&M cannot predict when such a site may be available, but Utah licenses a
low-level radioactive waste disposal sites which currently
accepts low-level radioactive waste from Michigan. I&M’s access
to the Barnwell, South Carolina facility ended in 2008. With some
modifications to existing facilities, I&M will have capacity for onsite
storage of that waste previously shipped to Barnwell, South Carolina for the
duration of its licensed operation of Cook Plant. There is currently
no set date limiting I&M’s access to the Utah facility; however this
facility does not accept all classifications of low level waste.

In
January 2000, OPCo and NPC, an affiliate of Buckeye, entered into an agreement
relating to the construction and operation of a 510 MW gas-fired electric
generating peaking facility to be owned by NPC and called the Mone
Plant. OPCo is entitled to 100% of the power generated by the Mone
Plant, and is responsible for the fuel and other costs of the facility through
May 2012, as extended. Following that, NPC and OPCo will be entitled to 80% and
20%, respectively, of the power of the Mone Plant, and both parties will
generally be responsible for their allocable portion of the fuel and other costs
of the facility.

Certain
Power Agreements

I&M: The Unit Power Agreement
between AEGCo and I&M, dated March 31, 1982, provides for the sale by AEGCo
to I&M of all the capacity (and the energy associated therewith) available
to AEGCo at the Rockport Plant. Whether or not power is available from AEGCo,
I&M is obligated to pay a demand charge for the right to receive such power
(and an energy charge for any associated energy taken by
I&M). The agreement will continue in effect until the last of the
lease terms of Unit 2 of the Rockport Plant has expired (currently December
2022) unless extended in specified circumstances.

Pursuant
to an assignment between I&M and KPCo, and a unit power agreement between
KPCo and AEGCo, AEGCo sells KPCo 30% of the capacity (and the energy associated
therewith) available to AEGCo from both units of the Rockport Plant. KPCo has
agreed to pay to AEGCo the amounts that I&M would have paid AEGCo under the
terms of the Unit Power Agreement between AEGCo and I&M for such
entitlement. The KPCo unit power agreement expires in December
2022.

CSPCo: The Unit Power Agreement
between AEGCo and CSPCo, dated March 15, 2007, provides for the sale by AEGCo to
CSPCo of all the capacity and associated unit contingent energy and ancillary
services available to AEGCo at the Lawrenceburg Plant that are scheduled and
dispatched by CSPCo. CSPCo is obligated to pay a capacity charge
(whether or not power is available from the Lawrenceburg Plant), and the fuel,
operating and maintenance charges associated with the energy dispatched by
CSPCo, and to reimburse AEGCo for other costs associated with the operation and
ownership of the Lawrenceburg Plant. The agreement will continue in
effect until December 31, 2017 unless extended as set forth in the
agreement.

OVEC:AEP and several
unaffiliated utility companies jointly own OVEC. The aggregate equity
participation of AEP in OVEC is 43.47%. Until September 1, 2001, OVEC
supplied from its generating capacity the power requirements of a uranium
enrichment plant near Portsmouth, Ohio owned by the DOE. The
sponsoring companies are now entitled to receive and obligated to pay for all
OVEC capacity (approximately 2,200 MW) in proportion to their respective power
participation ratios. The aggregate power participation ratio of
APCo, CSPCo, I&M and OPCo is 43.47%. The proceeds from the sale of power by
OVEC are designed to be sufficient for OVEC to meet its operating expenses and
fixed costs and to provide a return on its equity capital. The
Amended and Restated Inter-Company Power Agreement, which defines the rights of
the owners and sets the power participation ratio of each, will expire by its
terms on March 12, 2026. AEP and the other owners have authorized
environmental investments related to their ownership interests. As of
December 2008, OVEC’s Board of Directors has authorized capital expenditures
totaling $981.6 million in connection with the engineering and construction of
flue gas desulfurization (sulfur dioxide scrubber) projects and the associated
scrubber waste disposal landfills at its two generating
plants. OVEC’s Board of Directors has delayed for at least eighteen
months final completion of construction on one of the plants. If
approved and fully funded, the estimated total cost to complete the scrubber and
landfill projects would be in excess of $1.2 billion, which OVEC would expect to
finance through issuing debt.

ELECTRIC
TRANSMISSION AND DISTRIBUTION

General

AEP’s
public utility subsidiaries (other than AEGCo) own and operate transmission and
distribution lines and other facilities to deliver electric power. See Item 2—Properties for more
information regarding the transmission and distribution lines. Most of the
transmission and distribution services are sold, in combination with electric
power, to retail customers of AEP’s public utility subsidiaries in their service
territories. These sales are made at rates approved by the state
utility commissions of the states in which they operate, and in some instances,
approved by the FERC. See Item 1 –Utility Operations -
Regulation—Rates. The FERC regulates and approves the rates for wholesale
transmission transactions. See Item 1 –Utility Operations -
Regulation—FERC. As discussed below, some transmission
services also are separately sold to non-affiliated companies.

AEP’s
public utility subsidiaries (other than AEGCo) hold franchises or other rights
to provide electric service in various municipalities and regions in their
service areas. In some cases, these franchises provide the utility
with the exclusive right to provide electric service. These
franchises have varying provisions and expiration dates. In general,
the operating companies consider their franchises to be adequate for the conduct
of their business. For a discussion of competition in the sale of
power, see Item 1 –Utility
Operations - Competition.

AEP
Transmission Pool

Transmission
Agreement:APCo, CSPCo, I&M,
KPCo and OPCo operate their transmission lines as a single interconnected and
coordinated system in AEP East transmission zone and are parties to the TEA,
defining how they share the costs and benefits associated with their relative
ownership of the extra-high-voltage transmission system (facilities rated 345kV
and above) and certain facilities operated at lower voltages (138kV up to
345kV). The TEA has been approved by the FERC. Sharing under the TEA is based
upon each company’s “member-load-ratio.” The member-load-ratio is
calculated monthly by dividing such company’s highest monthly peak demand for
the last twelve months by the aggregate of the highest monthly peak demand for
the last twelve months for all east zone operating companies. The
respective peak demands and member-load-ratios as of December 31, 2008 are set
forth above in the section titled ELECTRIC GENERATION – AEP
Power Pool and CSW Operating Agreement.

The
following table shows the net (credits) or charges allocated among the parties
to the TEA during the years ended December 31, 2006, 2007 and 2008:

2006

2007

2008

(in
thousands)

APCo

$(16,000)

$(25,000)

$(29,000)

CSPCo

46,000

51,900

55,000

I&M

(37,000)

(34,600)

(37,000)

KPCo

(2,000)

(800)

(2,000)

OPCo

9,000

8,500

13,000

Transmission
Coordination Agreement:PSO, SWEPCo, TCC, TNC
and AEPSC are parties to the TCA, which has been approved by the
FERC. Under the TCA, a coordinating committee is charged with the
responsibility of (i) overseeing the coordinated planning of the transmission
facilities of the AEP West companies in the AEP West transmission zone,
including the performance of transmission planning studies, (ii) the interaction
of such subsidiaries with independent system operators and other regional bodies
interested in transmission planning and (iii) compliance with the terms of the
OATT filed with the FERC and the rules of the FERC relating to such
tariff. Pursuant to the TCA, the AEP West companies have delegated to
AEPSC responsibility for monitoring the reliability of their transmission
systems and administering the AEP OATT on their behalf. Prior to September 2005,
the TCA also provided for the allocation among the AEP West companies of
revenues collected for transmission and ancillary services provided under the
AEP OATT. Since then, these allocations have been determined by the
FERC-approved OATT for the SPP (with respect to PSO and SWEPCo) and
PUCT-approved protocols for ERCOT (with respect to TCC and TNC).

The
following table shows the net (credits) or charges allocated pursuant to the SPP
OATT and ERCOT protocols as described above during the years ended December 31,
2006, 2007 and 2008:

2006

2007

2008

(in
thousands)

PSO

$1,800

$500

$8,200

SWEPCo

(1,900)

(500)

(8,200)

TCC

1,100

1,100

1,500

TNC

(1,000)

(1,100)

(1,500)

Transmission
Services for Non-Affiliates:In addition to
providing transmission services in connection with their own power sales, AEP’s
public utility subsidiaries through RTOs also provide transmission services for
non-affiliated companies. See Item 1 –Utility Operations –
Electric Transmission and Distribution - Regional Transmission Organizations,
below.
Transmission of electric power by AEP’s public utility subsidiaries is
regulated by the FERC.

Coordination of
East and West Zone Transmission:AEP’s System
Transmission Integration Agreement provides for the integration and coordination
of the planning, operation and maintenance of the transmission facilities of AEP
East and AEP West companies. The System Transmission Integration Agreement
functions as an umbrella agreement in addition to the TEA and the TCA. The
System Transmission Integration Agreement contains two service schedules that
govern:

·

The
allocation of transmission costs and revenues
and

·

The
allocation of third-party transmission costs and revenues and System
dispatch costs.

The
System Transmission Integration Agreement contemplates that additional service
schedules may be added as circumstances warrant.

Regional
Transmission Organizations

The AEP
East Companies are members of PJM (a FERC-approved RTO). SWEPCo and
PSO are members of the SPP (another FERC-approved RTO). RTOs operate,
plan and control utility transmission assets in a manner designed to provide
open access to such assets in a way that prevents discrimination between
participants owning transmission assets and those that do not. The remaining AEP
West companies (TCC and TNC) are members of ERCOT. See Note 4 to the
consolidated financial statements, entitled Rate Matters, included in the
2008 Annual Reports under the heading entitled Regional Transmission Rate
Proceedings at the FERC for additional information regarding
RTOs.

REGULATION

General

Except
for transmission and/or retail generation sales in certain of its jurisdictions,
AEP’s public utility subsidiaries’ retail rates and certain other matters are
subject to traditional cost-based regulation by the state utility
commissions. See Item 1 – Utility Operations -
Electric Restructuring and Customer Choice Legislation and Rates, below. AEP’s
subsidiaries are also subject to regulation by the FERC under the FPA with
respect to wholesale power and transmission service transactions as well as
certain unbundled retail transmission rates mainly in Ohio. I&M
is subject to regulation by the NRC under the Atomic Energy Act of 1954, as
amended, with respect to the operation of the Cook Plant. AEP and its
public utility subsidiaries are also subject to the regulatory provisions of
EPACT, much of which is administered by the FERC. EPACT contains key
provisions affecting the electric power industry such as giving the FERC
“backstop” transmission siting authority as well as increased utility merger
oversight. The law also provides incentives and funding for clean
coal technologies and initiatives to voluntarily reduce greenhouse
gases.

Rates

Historically,
state utility commissions have established electric service rates on a
cost-of-service basis, which is designed to allow a utility an opportunity to
recover its cost of providing service and to earn a reasonable return on its
investment used in providing that service. A utility’s cost of service generally
reflects its operating expenses, including operation and maintenance expense,
depreciation expense and taxes. State utility commissions periodically adjust
rates pursuant to a review of (i) a utility’s adjusted revenues and expenses
during a defined test period and (ii) such utility’s level of investment. Absent
a legal limitation, such as a law limiting the frequency of rate changes or
capping rates for a period of time, a state utility commission can review and
change rates on its own initiative. Some states may initiate reviews at the
request of a utility, customer, governmental or other representative of a group
of customers. Such parties may, however, agree with one another not to request
reviews of or changes to rates for a specified period of time.

Public
utilities have traditionally financed capital investments until the new asset
was placed in service. Provided the asset was found to be a prudent
investment, it was then added to rate base and entitled to a return through rate
recovery. Given long lead times in construction, the high costs of
plant and equipment and difficult capital markets, we are actively pursuing
strategies to accelerate rate recognition of investments and cash
flow. AEP representatives are leading the dialogue with our state
commissioners and legislators on alternative ratemaking options to reduce
regulatory lag and enhance certainty in the process. These
options include pre-approvals, a return on construction work in progress,
rider/trackers, securitization, formula rates and the inclusion of future
test-year projections into rates.

In many
jurisdictions, the rates of AEP’s public utility subsidiaries are generally
based on the cost of providing traditional bundled electric service (i.e.,
generation, transmission and distribution service). In the ERCOT area of Texas,
our utilities have exited the generation business and they currently charge
unbundled cost-based rates for transmission and distribution service
only. In Ohio, rates for electric service are unbundled for
generation, transmission and distribution service. Historically, the
state regulatory frameworks in the service area of the AEP System reflected
specified fuel costs as part of bundled (or, more recently, unbundled) rates or
incorporated fuel adjustment clauses in a utility’s rates and tariffs. Fuel
adjustment clauses permit periodic adjustments to fuel cost recovery from
customers and therefore provide protection against exposure to fuel cost
changes. While the historical framework remains in a portion of AEP’s service
territory, CSPCo and OPCo did not have a fuel adjustment clause to recover
increased fuel costs in Ohio through 2008. CSPCo and OPCo are seeking
to implement a fuel cost recovery mechanism.

The
following state-by-state analysis summarizes the regulatory environment of
certain major jurisdictions in which AEP operates. Several public utility
subsidiaries operate in more than one jurisdiction. See Note 4 to the
consolidated financial statements, entitled Rate Matters, included in the
2008 Annual Reports, for more information regarding pending rate
matters.

Indiana: I&M provides retail
electric service in Indiana at bundled rates approved by the IURC, with rates
set on a cost-of-service basis. Indiana provides for timely fuel and
purchased power cost recovery through a fuel cost recovery
mechanism.

Ohio: CSPCo and OPCo each
operated as a functionally separated utility and provided “default” retail
electric service to customers at unbundled rates pursuant to the Ohio
Act. Pursuant to rate stabilization plans approved by the PUCO, CSPCo
and OPCo provide retail generation service at rates approved by the
PUCO. CSPCo and OPCo are providing and will continue to provide
distribution services to retail customers at cost based rates approved by the
PUCO. Transmission services will continue to be provided at OATT
rates based on rates established by the FERC. CSPCo and OPCo’s
generation/supply rates are no longer cost based regulated. Pursuant to the Ohio
Amendments, CSPCo and OPCo have filed their ESP with PUCO, each requesting an
annual rate increase for 2009 through 2011 that would not exceed approximately
15% per year. A significant portion of the requested increases
results from the implementation of a fuel cost recovery mechanism that primarily
includes fuel costs, purchased power costs including mandated renewable energy,
consumables such as urea, other variable production costs and gains and losses
on sales of emission allowances. CSPCo and OPCo have not had a fuel
adjustment clause since 1999.

Oklahoma: PSO provides retail
electric service in Oklahoma at bundled rates approved by the
OCC. PSO’s rates are set on a cost-of-service basis. Fuel and
purchased energy costs above the amount included in base rates are recovered by
applying a fuel adjustment factor to retail kilowatt-hour sales. The factor is
generally adjusted annually and is based upon forecasted fuel and purchased
energy costs. Over or under collections of fuel costs for prior periods are
returned to or recovered from customers in the year following when new annual
factors are established.

Texas:TCC has sold all of its
generation assets. TNC has one active generation
unit. However, all of the output from that unit is sold to a
non-utility affiliate pursuant to an agreement effective through
2027. Most retail customers in TCC’s and TNC’s ERCOT service area of
Texas are served through non-affiliated Retail Electric Providers
(“REPs”). TCC and TNC provide retail transmission and distribution
service on a cost-of-service basis at rates approved by the PUCT and wholesale
transmission service under tariffs approved by the FERC consistent with PUCT
rules. In August 2006, the PUCT delayed competition in the SPP area
of Texas until at least January 1, 2011. As such, the PUCT continues to approve
base and fuel rates for SWEPCo’s Texas operations on a cost of service
basis.

Virginia:APCo currently provides
retail electric service in Virginia at unbundled rates. In April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation and supply rates after the
December 31, 2008 expiration of capped rates. The law
provides for, among other things, biennial rate reviews beginning in 2009; rate
adjustment clauses for the recovery of a variety of costs and a minimum allowed
return on equity which will be based on the average earned return on equity of
regional vertically integrated electric utilities. The law also
provides that utilities may retain a minimum of 25% of the margins from
off-system sales with the remaining margins from such sales credited against a
fuel adjustment clause factor with a true-up to actual.

West
Virginia: APCo
and WPCo provide retail electric service at bundled rates approved by the WVPSC.
West Virginia generally allows for timely recovery of fuel costs through an
expanded net energy clause which trues up to actual expenses.

Other
Jurisdictions:
The public utility subsidiaries of AEP also provide service at cost based
regulated bundled rates in Arkansas, Kentucky, Louisiana and Tennessee and
regulated unbundled rates in Michigan. These jurisdictions provide
for the timely recovery of fuel costs through fuel adjustment clauses that
true-up to actual expenses.

The
following table illustrates the current rate regulation status of the states in
which the public utility subsidiaries of AEP operate:

Fuel
Clause Rates(1)

Off-System
Sales Profits

Percentage
of AEP System

Status
of Base Rates for

Shared
with

Retail

Jurisdiction

Power
Supply

Energy
Delivery

Status

Ratepayers

Revenues(2)

Ohio

See
footnote 3

See
footnote 3

See
footnote 3

Not
applicable

32%

Oklahoma

Not
capped or frozen

Not
capped or frozen

Active

Yes

14%

Texas
ERCOT

Not
applicable (4)

Not
capped or frozen

Not
applicable

Not
applicable

8%

Texas
SPP

Not
capped or frozen (4)

Not
capped or frozen

Active

Yes

4%

West
Virginia

Not
capped or frozen

Not
capped or frozen

Active

Yes

10%

Indiana

Not
capped or frozen

Not
capped or frozen

Active

No

9%

Virginia

Not
capped or frozen (5)

Not
capped or frozen (5)

Active

Yes

9%

Louisiana

Not
capped or frozen

Not
capped or frozen

Active

Yes,
above base levels

4%

Kentucky

Not
capped or frozen

Not
capped or frozen

Active

Yes,
above and below base levels(6)

4%

Arkansas

Not
capped or frozen

Not
capped or frozen

Active

Yes,
above base levels

3%

Michigan

Not
capped or frozen

Not
capped or frozen

Active

Yes,
in some areas

2%

Tennessee

See
footnote 7

Not
capped or frozen

Active

Not
applicable

1%

(1)

Includes,
where applicable, fuel and fuel portion of purchased
power.

(2)

Represents
the percentage of revenues from sales to retail customers from AEP utility
companies operating in each state to the total AEP System revenues from
sales to retail customers for the year ended December 31,
2008.

(3)

The
PUCO approved rate stabilization plans (RSP) filed by CSPCo and OPCo that
began after the market development period and extended through December
31, 2008 during which OPCo’s retail generation rates increased 7% annually
and CSPCo’s retail generation rates increased 3%
annually. Distribution rates were frozen, with certain
exceptions, through December 31, 2008. Pursuant to the Ohio
Amendments, in July 2008, CSPCo and OPCo filed ESP with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo have
requested retroactive application of the new rates, including the fuel
cost recovery mechanism, back to January 1, 2009 upon approval of the
ESP. In December 2008, the PUCO ordered that CSPCo and OPCo
continue using their current RSP rates until the PUCO issues a ruling on
the ESP or the end of the February 2009 billing cycle, whichever comes
first. In January 2009, CSPCo and OPCo filed an application
with the PUCO requesting the PUCO to authorize deferred fuel accounting
beginning January 1, 2009. See Note 4 to the consolidated
financial statements, entitled Rate
Matters.

(4)

TCC
and TNC are no longer in the retail generation supply
business. TCC and TNC provide only regulated delivery services
in ERCOT. SWEPCo is vertically integrated utility that provides
retail electric service in the SPP area of
Texas.

(5)

Rates
in Virginia were capped, subject to adjustment, through
2008. Beginning January 1, 2009, rates are neither capped nor
frozen.

(6)

If
the monthly off-system sales profits do not meet the monthly level built
into base rates, ratepayers reimburse KPCo for a portion of the
shortfall. If the monthly off-system sales profits exceed the
monthly base amount built into base rates, KPCo reimburses ratepayers for
a portion of the excess.

(7)

Prior
to January 1, 2009, base rates for power supply were not capped or
frozen. Effective January 1, 2009, base rates for power supply
will phase-in increases of $24 million, $3 million and $9 million for the
years beginning January 1, 2009, 2010 and 2011,
respectively. Any filing to increase the amount Kingsport pays
for the non-fuel component of its purchase power, other than as discussed
above, cannot be made prior to January 1,
2012.

FERC

Under the
FPA, the FERC regulates rates for interstate sales at wholesale, transmission of
electric power, accounting and other matters, including construction and
operation of hydroelectric projects. The FERC regulations require AEP to provide
open access transmission service at FERC-approved rates. The FERC also regulates
unbundled transmission service to retail customers. The FERC also
regulates the sale of power for resale in interstate commerce by (i) approving
contracts for wholesale sales to municipal and cooperative utilities and (ii)
granting authority to public utilities to sell power at wholesale at
market-based rates upon a showing that the seller lacks the ability to
improperly influence market prices. Except for wholesale power that
AEP delivers within its control area of the SPP, AEP has market-rate authority
from the FERC, under which much of its wholesale marketing activity takes
place. The FERC requires each public utility that owns or controls
interstate transmission facilities to, directly or through an RTO, file an open
access network and point-to-point transmission tariff that offers services
comparable to the utility’s own uses of its transmission system. The FERC also
requires all transmitting utilities, directly or through an RTO, to establish an
OASIS, which electronically posts transmission information such as available
capacity and prices, and require utilities to comply with Standards of Conduct
that prohibit utilities’ transmission employees from providing non-public
transmission information to the utility’s marketing employees.

The FERC
oversees the voluntary formation of RTOs, entities created to operate, plan and
control utility transmission assets. Order 2000 also prescribes certain
characteristics and functions of acceptable RTO proposals. As a
condition of the FERC’s approval in 2000 of AEP’s merger with CSW, AEP was
required to transfer functional control of its transmission facilities,
including OASIS and tariff responsibilities, to one or more RTOs. As
a result, the AEP East Companies are members of PJM. SWEPCo and PSO are members
of SPP.

The FERC
has jurisdiction over the issuances of securities of our public utility
subsidiaries, the acquisition of securities of utilities, the acquisition or
sale of certain utility assets, and mergers with another electric utility or
holding company. In addition, both the FERC and state regulators are
permitted to review the books and records of any company within a holding
company system. EPACT gives the FERC “backstop” transmission siting
authority as well as increased utility merger oversight.

ELECTRIC
RESTRUCTURING AND CUSTOMER CHOICE LEGISLATION

Certain
states in AEP’s service area have adopted restructuring or customer choice
legislation. In general, this legislation provides for a transition from bundled
cost-based rate regulated electric service to unbundled cost-based rates for
transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier. At a minimum, this legislation
allows retail customers to select alternative generation suppliers. Electric
restructuring and/or customer choice began on January 1, 2001 in Ohio and on
January 1, 2002 in Michigan and the ERCOT area of Texas. Electric restructuring
in the SPP area of Texas has been delayed by the PUCT until at least 2011. AEP’s
public utility subsidiaries operate in both the ERCOT and SPP areas of
Texas. Customer choice also began in Virginia on January 1, 2002, but
ended in 2009 for residential customers (except those seeking green
power) pursuant to a new law providing for the re-regulation of electric
utilities’ generation and supply rates.

Ohio
Restructuring

Currently,
the Ohio Act requires vertically integrated electric utility companies that are
in the business of providing competitive retail electric service in Ohio to
separate their generating functions from their transmission and distribution
functions. Following the market development period (which ended December 31,
2005), retail customers receive distribution and, where applicable, transmission
service from the incumbent utility whose cost-based distribution rates are
approved by the PUCO and whose cost-based transmission rates are based on rates
established by the FERC. See Item 1 – Utility Operations -
Regulation—FERC for a discussion of FERC regulation of transmission
rates, Regulation—Rates—Ohio
and Note 4 to the consolidated financial statements entitled Rate Matters, included in
the 2008 Annual Reports,
for a discussion of the impact of restructuring on distribution rates.
The PUCO has authorized CSPCo and OPCo to remain functionally
separated.

Pursuant
to the Ohio Amendments, CSPCo and OPCo have filed ESP with the PUCO, each
requesting an annual rate increase for 2009 through 2011 that would not exceed
approximately 15% per year. A significant portion of the requested
increases results from the implementation of a fuel cost recovery mechanism that
primarily includes fuel costs, purchased power costs including mandated
renewable energy, consumables such as urea, other variable production costs and
gains and losses on sales of emission allowances. See Note 4 to the
consolidated financial statements, entitled Rate Matters, included in the
2008 Annual Reports, for more information.

Texas
Restructuring

The Texas
Act substantially amended the regulatory structure governing electric utilities
in Texas in order to allow retail electric competition for
customers. Among other things, the Texas Act:

·

gave
Texas customers the opportunity to choose their REP beginning January 1,
2002 (delayed until at least 2011 in the SPP portion of
Texas),

·

required
each utility to legally separate into a REP, a power generation company
and a transmission and distribution utility,
and

·

required
that REPs provide electricity at generally unregulated rates, except that
until January 1, 2007 the prices that could be charged to residential and
small commercial customers by REPs affiliated with a utility within the
affiliated utility’s service area were set by the PUCT, until certain
conditions in the Texas Act were
met.

The Texas
Act also provides each affected utility an opportunity to recover its
generation-related regulatory assets and stranded costs resulting from the legal
separation of the transmission and distribution utility from the generation
facilities and the related introduction of retail electric competition at
non-cost based rates for generation/supply of electricity. Regulatory
assets consist of the Texas jurisdictional amount of generation-related
regulatory assets and liabilities in the audited financial statements as of
December 31, 1998. Stranded costs consist of the excess of the net
regulated book value of generation assets (as of December 31, 2001) over the
market value of those assets, taking specified factors into account, as
ultimately determined in a PUCT true-up proceeding.

TCC
elected to sell its generating facilities to establish its recoverable stranded
costs. In May 2005, TCC filed its stranded cost quantification
application, or true-up proceeding, with the PUCT seeking recovery of $2.4
billion of net stranded generation costs and other recoverable true-up
items. A final order was issued in April 2006. In the
final order, the PUCT determined TCC’s net stranded generation costs and other
recoverable true-up items to be approximately $1.475 billion. Other
parties have appealed the PUCT’s final order as unwarranted or too large; TCC
has appealed seeking additional recovery consistent with the Texas Act and
related rules. TCC intends to appeal any final adverse rulings
regarding the PUCT’s order in the true-up proceedings.

After
PUCT approval, in October 2006 TCC issued $1.74 billion of securitization bonds,
including additional issuance and carrying costs through the date of
issuance. For a discussion of (i) regulatory assets and stranded
costs subject to recovery by TCC and (ii) rate adjustments made after
implementation of restructuring to allow recovery of certain costs by or with
respect to TCC and TNC, see Note 4 to the consolidated financial statements
entitled Rate Matters
included in the 2008 Annual Reports.

Michigan
Customer Choice

Customer
choice commenced for I&M’s Michigan customers on January 1,
2002. In October 2008, the Governor of Michigan signed legislation to
limit customer choice load to no more than 10% of the annual retail load for the
preceding calendar year. Rates for retail electric service for
I&M’s Michigan customers were unbundled (though they continue to be cost
based regulated) to allow customers the ability to evaluate the cost of
generation service for comparison with other suppliers. At December 31, 2008,
none of I&M’s Michigan customers have elected to change suppliers and no
alternative electric suppliers are registered to compete in I&M’s Michigan
service territory.

Virginia
Re-regulation

In April
2007, the Virginia legislature adopted a comprehensive law providing for the
re-regulation of electric utilities’ generation and supply rates after the
December 31, 2008 expiration of adjusted capped
rates. The law provides for, among other things, biennial
rate reviews beginning in 2009; rate adjustment clauses for the recovery of a
variety of costs and a minimum allowed return on equity which will be based on
the average earned return on equity of regional vertically integrated electric
utilities. The law also provides that utilities may retain a minimum
of 25% of the margins from off-system sales with the remaining margins from such
sales credited against APCo’s fuel adjustment clause factor with a true-up to
actual.

COMPETITION

The
public utility subsidiaries of AEP, like the electric industry generally, face
competition in the sale of available power on a wholesale basis, primarily to
other public utilities and power marketers. The Energy Policy Act of 1992 was
designed, among other things, to foster competition in the wholesale market by
creating a generation market with fewer barriers to entry and mandating that all
generators have equal access to transmission services. As a result, there are
more generators able to participate in this market. The principal factors in
competing for wholesale sales are price (including fuel costs), availability of
capacity and power and reliability of service.

AEP’s
public utility subsidiaries also compete with self-generation and with
distributors of other energy sources, such as natural gas, fuel oil and coal,
within their service areas. The primary factors in such competition are price,
reliability of service and the capability of customers to utilize sources of
energy other than electric power. With respect to competing generators and
self-generation, the public utility subsidiaries of AEP believe that they
generally maintain a favorable competitive position. With respect to alternative
sources of energy, the public utility subsidiaries of AEP believe that the
reliability of their service and the limited ability of customers to substitute
other cost-effective sources for electric power place them in a favorable
competitive position, even though their prices may be higher than the costs of
some other sources of energy.

Significant
changes in the global economy have led to increased price competition for
industrial customers in the United States, including those served by the AEP
System. Some of these industrial customers have requested price reductions from
their suppliers of electric power. In addition, industrial customers that are
downsizing or reorganizing often close a facility based upon its costs, which
may include, among other things, the cost of electric power. The public utility
subsidiaries of AEP cooperate with such customers to meet their business needs
through, for example, providing various off-peak or interruptible supply options
pursuant to tariffs filed with, and approved by, the various state commissions.
Occasionally, these rates are negotiated with the customer, and then filed with
the state commissions for approval. The public utility subsidiaries of AEP
believe that they are unlikely to be materially affected by this competition in
an adverse manner.

SEASONALITY

The sale
of electric power is generally a seasonal business. In many parts of the
country, demand for power peaks during the hot summer months, with market prices
also peaking at that time. In other areas, power demand peaks during the winter.
The pattern of this fluctuation may change due to the nature and location of
AEP’s facilities and the terms of power sale contracts into which AEP enters. In
addition, AEP has historically sold less power, and consequently earned less
income, when weather conditions are milder. Unusually mild weather in the future
could diminish AEP’s results of operations and may impact its financial
condition. Conversely, unusually extreme weather conditions could
increase AEP’s results of operations.

AEP RIVER
OPERATIONS

Our AEP
River Operations Segment transports coal and dry bulk commodities primarily on
the Ohio, Illinois, and lower Mississippi rivers. Almost all of our
customers are nonaffiliated third parties who obtain the transport of coal and
dry bulk commodities for various uses. We charge these customers
market rates for the purpose of making a profit. Depending on market
conditions and other factors, including barge availability, we permit AEP
utility subsidiary affiliates to use certain of our equipment at rates that
reflect our cost. Our affiliated utility customers procure the
transport of coal for use as fuel in their respective generating
plants. We charge affiliated customers rates that reflect our
costs. AEP River Operations includes approximately 2,252 barges, 42
towboats and 22 harbor boats that we own or lease. These assets are separate
from the barges and towboats dedicated exclusively to transporting coal for use
as fuel in our own generating facilities discussed under the prior
segment. See Item 1
– Utility Operations - Electric Generation —Fuel Supply—Coal and
Lignite.

Competition
within the barging industry for major commodity contracts is intense, with a
number of companies offering transportation services in the waterways we serve.
We compete with other carriers primarily on the basis of commodity shipping
rates, but also with respect tocustomer service,
available routes, value-added services (including scheduling convenience and
flexibility), information timeliness and equipment. The industry continues
to experience consolidation. The resulting companies
increasingly offer the widespread geographic reach necessary to support major
national customers. Demand for barging services can be seasonal,
particularly with respect to the movement of harvested agricultural commodities
(beginning in the late summer and extending through the fall). Cold
winter weather may also limit our operations when certain of the waterways we
serve are closed.

Our
transportation operations are subject to regulation by the U.S. Coast
Guard, federal laws, state laws and certain international
conventions. Legislation has been proposed that could make our
towboats subject to inspection by the U.S. Coast Guard.

GENERATION AND
MARKETING

Our
Generation and Marketing Segment consists of non-utility generating assets and a
competitive power supply and energy trading and marketing
business. We enter into short and long-term transactions to buy or
sell capacity, energy and ancillary services primarily in the ERCOT
market. As of December 31, 2008, the assets utilized in this segment
included approximately 310 MW of company-owned domestic wind power
facilities, 75MW of
domestic wind power from a long-term purchase power agreement and 377 MW of
coal-fired capacity which was obtained through an agreement effective through
2027 that transfers TNC’s interestin the Oklaunion power
station to AEP Energy Partners, Inc. During first quarter of 2009,
one of our non-utility affiliates, AEP Energy Partners, Inc., entered into a
purchase power agreement effective through 2029 that entitles us to the output
of a wind farm of approximately 100MW capacity. TNC’s transfer of
coal-fired generation capacity is in order to comply with the separation
requirements of the Texas Act. The power obtained from the Oklaunion
power station is marketed and sold in ERCOT. We are regulated by the
PUCT for transactions inside ERCOT and by the FERC for transactions outside of
ERCOT. While peak load in ERCOT typically occurs in the summer, we do
not necessarily expect seasonal variation in our operations.

OTHER

Plaquemine
Cogeneration Facility

Pursuant
to an agreement with Dow, AEP constructed an 880 MW cogeneration facility
(“Facility”) at Dow’s chemical facility in Plaquemine, Louisiana that achieved
commercial operation status in 2004. Dow used a portion of the energy
produced by the Facility and sold the excess power to us. We agreed
to sell up to all of the excess 800 MW to Tractebel. Litigation in
connection with that power agreement was settled in August, 2005. For
more information, see Note 6 to the consolidated financial statements entitled
Commitments, Guarantees and
Contingencies. In November 2006, we sold our interest in the
Facility to Dow. Negotiations for the sale resulted in an after-tax
impairment of approximately $136 million. See Note 7 to the
consolidated financial statements entitled Acquisitions, Dispositions,
Discontinued Operations
and
Impairments.

For
information regarding other non-core investments, see Note 7 to the consolidated
financial statements entitled Acquisitions, Dispositions,
Discontinued Operations
and
Impairments,
included in the 2008 Annual Reports.

ITEM
1A. RISK
FACTORS

General
Risks of Our Regulated Operations

We may not be able to recover the
costs of our substantial planned investment in capital improvements and
additions.(Applies to each
registrant.)

Our
business plan calls for extensive investment in capital improvements and
additions, including the installation of environmental upgrades and retrofits,
construction and/or acquisition of additional generation units and transmission
facilities, modernizing existing infrastructure as well as other initiatives.
Our public utility subsidiaries currently provide service at rates approved by
one or more regulatory commissions. If these regulatory commissions
do not approve adjustments to the rates we charge, we would not be able to
recover the costs associated with our planned extensive
investment. This would cause our financial results to be
diminished. While we may seek to limit the impact of any denied
recovery by attempting to reduce the scope of our capital investment, there can
be no assurance as to the effectiveness of any such mitigation efforts,
particularly with respect to previously incurred costs and
commitments.

Our
planned capital investment program coincides with a material increase in the
price of the fuels used to generate electricity. Most of our
jurisdictions have fuel clauses that permit us to recover these increased fuel
costs through rates without a general rate case. While prudent
capital investment and variable fuel costs each generally warrant recovery, in
practical terms our regulators could limit the amount or timing of increased
costs that we would recover through higher rates. Any such limitation
could cause our financial results to be diminished.

While Indiana permits the recovery of
prudently incurred
costs, our request for
rate recovery may not be approved in its entirety.(Applies to AEP and
I&M.)

In
January 2008, I&M filed a request to increase base rates in its Indiana
jurisdiction by approximately $80 million. The request included a return on
equity of 11.5% and the ability to introduce additional riders. The
requested increase is attributable to additional costs relating to operating in
the PJM, reliability enhancement, demand side management, additional off-system
sales margin sharing and environmental compliance costs. While
regulation in Indiana provides for a return on costs prudently incurred, there
can be no assurance that the IURC will approve all of the costs included in our
filing or that this process will result in rates providing full recovery in a
timely manner. If the IURC denies the requested rate recovery, it
could adversely impact future results of operations, cash flows and financial
conditions.

Our request for rate recovery in Ohio
may not be approvedin its entirety. (Applies to AEP, OPCo and
CSPCo)

In July
2008, within the parameters of the ESP, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo each requested
an annual rate increase for 2009 through 2011 that would not exceed
approximately 15% per year. A significant portion of the requested
increases results from the implementation of a fuel cost recovery mechanism that
primarily includes fuel costs, purchased power costs including renewable energy,
consumables such as urea, other variable production costs and gains and losses
on sales of emission allowances. Management expects a PUCO decision
on the ESP filings in the first quarter of 2009. CSPCo and OPCo have requested
retroactive application of the new rates back to January 1, 2009 upon
approval. If the PUCO denies all or part of the requested rate
recovery, it could have an adverse effect on future net income, cash flows and
financial condition.

We may not recover costs incurred to
begin constructing generating plants that are
canceled.(Applies to each
registrant)

Our
business plan for the construction of new generating units involves a number of
risks, including construction delays, nonperformance by equipment suppliers, and
increases in equipment and labor costs. To limit the risks of these construction
projects, we enter into equipment purchase orders and construction contracts and
incur engineering and design service costs in advance of receiving necessary
regulatory approvals and/or siting or environmental permits. If any of these
projects is canceled for any reason, including our failure to receive necessary
regulatory approvals and/or siting or environmental permits, we could incur
significant cancellation penalties under the equipment purchase orders and
construction contracts. In addition, if we have recorded any construction work
or investments as a regulatory asset we may need to impair that asset in the
event the project is canceled.

Rate regulation may delay or deny
full recovery of capital
improvements,
additions and other costs.(Applies to each
registrant.)

Our
public utility subsidiaries currently provide service at rates approved by one
or more regulatory commissions. These rates are generally regulated
based on an analysis of the applicable utility’s expenses incurred in a test
year. Thus, the rates a utility is allowed to charge may or may not
match its expenses at any given time. There may also be a delay
between the timing of when these costs are incurred and when these costs are
recovered. Traditionally, we have financed capital investments and
improvements until the new asset was placed in service. Provided the
asset was found to be a prudent investment, the asset was then added to rate
base and entitled to a return through rate recovery. Long lead times
in construction, the high costs of plant and equipment and difficult capital
markets has heightened the risks involved in our capital investments and
improvements. While we are actively pursuing strategies to accelerate rate
recognition of investments and cash flow, including pre-approvals, a return on
construction work in progress, rider/trackers, securitization, formula rates and
the inclusion of future test-year projections into rates, there can be no
assurance that these will be adopted, that the applicable regulatory commission
will judge all of our costs to have been prudently incurred or that the
regulatory process in which rates are determined will always result in rates
that will produce full recovery of our costs in a timely manner.

Certain of our revenues and results
of operations are subject to risks that are beyond our
control. (Applies to each
registrant.)

Our
operations are structured to comply with all applicable federal and state laws
and regulations and we take measures to minimize the risk of significant
disruptions. Material disruptions at one or more of our operational
facilities, however, could negatively impact our revenues, operating and capital
expenditures and results of operations. Such events may also create
additional risks related to the supply and/or cost of equipment and
materials. We could experience unexpected but significant
interruption due to several events, including:

Through
I&M, we own the Cook Plant. It consists of two nuclear generating
units for a rated capacity of 2,191 MW, or 8-9% of the electricity we
generate. We are, therefore, subject to the risks of nuclear
generation, which include the following:

·

the
potential harmful effects on the environment and human health resulting
from the operation of nuclear facilities and the storage, handling and
disposal of radioactive materials such as spent nuclear
fuel;

·

limitations
on the amounts and types of insurance commercially available to cover
losses that might arise in connection with our nuclear
operations;

·

uncertainties
with respect to contingencies and assessment amounts if insurance coverage
is inadequate (federal law requires owners of nuclear units to purchase
the maximum available amount of nuclear liability insurance and
potentially contribute to the losses of others);
and,

·

uncertainties
with respect to the technological and financial aspects of decommissioning
nuclear plants at the end of their licensed
lives.

There can
be no assurance that I&M’s preparations or risk mitigation measures will be
adequate if and when these risks are triggered.

The NRC
has broad authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities. In
the event of non-compliance, the NRC has the authority to impose fines or shut
down a unit, or both, depending upon its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements
promulgated by the NRC could necessitate substantial capital expenditures at
nuclear plants such as ours. In addition, although we have no reason
to anticipate a serious nuclear incident at our plants, if an incident did
occur, it could harm our results of operations or financial
condition. A major incident at a nuclear facility anywhere in the
world could cause the NRC to limit or prohibit the operation or licensing of any
domestic nuclear unit. Moreover, a major incident at any nuclear
facility in the U.S. could require us to make material contributory
payments.

The different regional power markets
in which we compete or will compete in the future have changing transmission
regulatory structures, which could affect our performance in these
regions. (Applies to each
registrant.)

Our
results are likely to be affected by differences in the market and transmission
regulatory structures in various regional power markets. The rules
governing the various regional power markets, including SPP and PJM, may also
change from time to time which could affect our costs or
revenues. Because the manner in which RTOs will evolve remains
unclear, we are unable to assess fully the impact that changes in these power
markets may have on our business.

The amount we charged third parties
for using our transmission facilities has been reduced and is subject to
refund.(Applies to AEP, APCo, CSPCo, I&M
and OPCo.)

In July
2003, the FERC issued an order directing PJM and MISO to make compliance filings
for their respective tariffs to eliminate the transaction-based charges for
through and out (T&O) transmission service on transactions where the energy
is delivered within those RTOs. The elimination of the T&O rates
reduced the transmission service revenues collected by the RTOs and thereby
reduced the revenues received by transmission owners under the RTOs’ revenue
distribution protocols. To mitigate the impact of lost T&O revenues, the
FERC approved temporary replacement seams elimination cost allocation (SECA)
transition rates beginning in December 2004 and extending through March
2006. Because intervenors objected to this decision, the SECA fees we
collected ($220 million) are subject to refund.

A hearing
was held in May 2006 to determine whether any of the SECA revenues should be
refunded. In August 2006, the ALJ ruled that the rate design for the recovery of
SECA charges was flawed and that a large portion was not recoverable. The ALJ
found that the SECA rates charged were unfair, unjust and discriminatory, and
that new compliance filings and refunds should be made. The ALJ also found that
unpaid SECA rates must be paid in the recommended reduced amount. The
FERC has not ruled on the matter. If the FERC upholds the decision of
the ALJ, it would disallow $90 million of the AEP East companies’ remaining
unsettled $108 million of unsettled gross SECA revenues. AEP has
settled $112 million of SECA revenues for $10 million. We have recorded a
provision for estimated settlement refunds. After completed and
in-process settlements, the AEP East companies have a remaining reserve balance
of $34 million to settle the remaining $108 million in unsettled gross SECA
revenues. Based on this settlement history, the $34 million reserve balance
should be adequate to absorb the potential refund of the remaining contested
SECA rates, assuming that the claims are settled. Payments in excess
of the reserve balance could harm our results of operations and financial
position.

An increase in the amount PJM charges
us for transmitting power over its network may not be fully
recoverable. (Applies to AEP and
I&M.)

On June
1, 2007, in response to a 2006 FERC order, PJM revised its methodology for
calculating the effect of transmission line losses in generation dispatch when
determining locational marginal prices. The new method is
designed to recognize the varying delivery costs of transmitting electricity
from individual generator locations to the places where customers consume the
energy. Due to the implementation of the new methodology, we
experienced an increase in the cost of transmitting energy to customer load
zones in the PJM. AEP has initiated discussions with PJM regarding
the impact of the new methodology and will pursue a modification through the
appropriate stakeholder processes. Management believes these
additional costs should be recoverable through retail and/or cost-based
wholesale rates. Recovery has been authorized by the PUCO, KPSC, VSCC
and WVPSC. The adjudication of the filing with the IURC is
pending. In the interim, such costs in these jurisdictions will have
an adverse effect on future results of operations and cash
flows. Management is unable to predict whether full recovery will
ultimately be approved.

We could be subject to higher costs
and/or penalties related to mandatory reliability standards. (Applies to each
registrant.)

As a
result of EPACT, owners and operators of the bulk power transmission system are
subject to mandatory reliability standards promulgated by the North American
Electric Reliability Corporation and enforced by the FERC. These standards,
which previously were being applied on a voluntary basis, became mandatory in
June 2007. The standards are based on the functions that need to be performed to
ensure the bulk power system operates reliably and is guided by reliability and
market interface principles. Compliance with new reliability standards may
subject us to higher operating costs and/or increased capital expenditures.
While we expect to recover costs and expenditures from customers through
regulated rates, there can be no assurance that the applicable commissions will
approve full recovery in a timely manner. If we were found not to be
in compliance with the mandatory reliability standards, we could be subject to
sanctions, including substantial monetary penalties, which likely would not be
recoverable from customers through regulated rates.

At times, demand for power could
exceed our supply capacity. (Applies to each
registrant.)

We are
currently obligated to supply power in parts of eleven states. From
time to time, because of unforeseen circumstances, the demand for power required
to meet these obligations could exceed our available generation
capacity. If this occurs, we would have to buy power from the
market. This would increase the pressure on our short-term debt
financing capacity in times of tight liquidity. We may not always
have the ability to pass these costs on to our customers, and the time lag
between incurring costs and recovery can be long. Since these
situations most often occur during periods of peak demand, it is possible that
the market price for power at that time would be very high. Even if a supply
shortage were brief, we could suffer substantial losses that could reduce our
results of operations.

Risks
Related to Market, Economic or Financial Volatility

If we are unable to access capital
markets on reasonable terms, it could have an adverse impact on our net income,
cash flows and financial condition. (Applies to each
registrant)

We rely
on access to capital markets as a significant source of liquidity for capital
requirements not satisfied by operating cash flows. The recent
volatility and reduced liquidity in the financial markets could affect our
ability to raise capital and fund our capital needs, including construction
costs and refinancing maturing indebtedness. In addition, if capital
is available only on less than reasonable terms or to borrowers whose
creditworthiness is better than ours, capital costs could increase
materially. Restricted access to capital markets and/or increased
borrowing costs could have an adverse impact on net income, cash flows and
financial condition.

The
credit ratings agencies periodically review our capital structure and the
quality and stability of our earnings. Any negative ratings actions
could constrain the capital available to our industry and could limit our access
to funding for our operations. Our business is capital intensive, and
we are dependent upon our ability to access capital at rates and on terms we
determine to be attractive. In the current period of market turmoil,
access to capital is difficult for all borrowers. If our ability to
access capital becomes significantly constrained, our costs of capital will
likely increase and our financial condition could be harmed and future results
of operations could be adversely affected.

If
Moody’s or S&P were to downgrade the long-term rating of any of the
securities of the registrants, particularly below
investment grade, the borrowing costs of that registrant would increase, which
would diminish its financial results. In addition, the registrant’s
potential pool of investors and funding sources could decrease. Over
the first two months of 2009, Moody’s placed the senior unsecured debt rating of
AEP on negative outlook, the senior unsecured debt rating of OPCo, SWEPCo, TCC
and TNC on review for possible downgrade and changed the outlook of APCo from
negative to stable. In February 2008 Fitch downgraded the senior
unsecured debt rating of PSO to BBB+ with stable outlook. Fitch
placed the senior unsecured debt rating of APCo and TCC on negative outlook in
May 2008 and February 2009, respectively.

Our power
trading business relies on the investment grade ratings of our individual public
utility subsidiaries’ senior unsecured long-term debt. Most of our
counterparties require the creditworthiness of an investment grade entity to
stand behind transactions. If those ratings were to decline below
investment grade, our ability to operate our power trading business profitably
would be diminished because we would likely have to deposit cash or cash-related
instruments which would reduce our profits.

The
performance of the capital markets affects the value of the assets that are held
in trust to satisfy future obligations under our defined benefit pension plans.
The recent deterioration of the capital markets has led to a decline in the
market value of these assets and a reduction in the benchmark discount rate with
respect to a return on these assets. Accordingly, we expect that our future
funding requirements of the obligations under our defined benefit plans to
significantly increase.

AEP has no income or cash flow apart
from dividends paid or other obligations due it from its
subsidiaries. (Applies to
AEP.)

AEP is a
holding company and has no operations of its own. Its ability to meet
its financial obligations associated with its indebtedness and to pay dividends
on its common stock is primarily dependent on the earnings and cash flows of its
operating subsidiaries, primarily its regulated utilities, and the ability of
its subsidiaries to pay dividends to, or repay loans from, AEP. Its
subsidiaries are separate and distinct legal entities that have no obligation
(apart from loans from AEP) to provide AEP with funds for its payment
obligations, whether by dividends, distributions or other payments. Payments to
AEP by its subsidiaries are also contingent upon their earnings and business
considerations. In addition, any payment of dividends, distributions or advances
by the utility subsidiaries to AEP would be subject to regulatory or contractual
restrictions. AEP indebtedness and common stock dividends are
effectively subordinated to all subsidiary indebtedness and preferred stock
obligations.

Our operating results may fluctuate
on a seasonal or
quarterly
basisand with general economic
conditions. (Applies to each
registrant.)

Electric
power generation is generally a seasonal business. In many parts of
the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks
during the winter. As a result, our overall operating results in the
future may fluctuate substantially on a seasonal basis. The pattern
of this fluctuation may change depending on the terms of power sale contracts
that we enter into. In addition, we have historically sold less
power, and consequently earned less income, when weather conditions are
milder. Unusually mild weather in the future could diminish our
results of operations and harm our financial condition. Conversely,
unusually extreme weather conditions could increase AEP’s results of operations
in a manner that would not likely be sustainable. Further,
deteriorating economic conditions generally result in reduced consumption by our
customers, particularly industrial customers who may curtail operations or cease
production entirely, while an expanding economic environment generally results
in increased revenues. As a result, our overall operating results in
the future may fluctuate on the basis of prevailing economic
conditions. For example, a leading customer of APCO, Century Aluminum
in West Virginia, announced in February 2009 that it was ceasing
operations.

Failure to attract and retain an
appropriately qualified workforce could harm our results of operations.
(Applies to each
registrant.)

Certain
events, such as an aging workforce without appropriate replacements, mismatch of
skillset or complement to future needs, or unavailability of contract resources
may lead to operating challenges and increased costs. The challenges include
lack of resources, loss of knowledge and a lengthy time period associated with
skill development. In this case, costs, including costs for contractors to
replace employees, productivity costs and safety costs, may rise. Failure to
hire and adequately train replacement employees, including the transfer of
significant internal historical knowledge and expertise to the new employees, or
the future availability and cost of contract labor may adversely affect the
ability to manage and operate our business. If we are unable to
successfully attract and retain an appropriately qualified workforce, our
results of operations could be negatively affected.

Parties we have engaged to provide
construction materials or services may fail to perform their obligations, which
could harm our results of operations. (Applies to each
registrant.)

Our
business plan calls for extensive investment in capital improvements and
additions, including the installation of environmental upgrades, construction of
additional generation units and transmission facilities as well as other
initiatives. We are exposed to the risk of substantial price
increases in the costs of materials used in construction. We have
engaged numerous contractors and entered into a large number of agreements to
acquire the necessary materials and/or obtain the required construction related
services. As a result, we are also exposed to the risk that these
contractors and other counterparties could breach their obligations to
us. Should the counterparties to these arrangements fail to perform,
we may be forced to enter into alternative arrangements at then-current market
prices that may exceed our contractual prices and almost certainly cause delays
in that and related projects. Although our agreements are
designed to mitigate the consequences of a potential default by the
counterparty, our actual exposure may be greater than these mitigation
provisions. This would cause our financial results to be diminished, and we
might incur losses or delays in completing construction.

Changes in commodity prices
and the costs of
transport may increase
our cost of producing power or decrease the amount we receive from selling
power, harming our financial performance. (Applies to each
registrant.)

We are
exposed to changes in the price and availability of coal and the price and
availability to transport coal because most of our generating capacity is
coal-fired. We have contracts of varying durations for the supply of
coal for most of our existing generation capacity, but as these contracts end or
otherwise are not honored, we may not be able to purchase coal on terms as
favorable as the current contracts. Similarly, we are exposed
to changes in the price and availability of emission
allowances. We use emission allowances based on the amount of
coal we use as fuel and the reductions achieved through emission controls and
other measures. According to our estimates, we have procured
sufficient emission allowances to cover our projected needs for the next two
years and for much of the projected needs for periods beyond
that. At some point, however, we may have to obtain additional
allowances and those purchases may not be on as favorable terms as those
currently obtained.

We also
own natural gas-fired facilities, which increases our exposure to market prices
of natural gas. Natural gas prices tend to be more volatile than prices for
other fuel sources. Our ability to make off-system sales at a profit is highly
dependent on the price of natural gas. As the price of natural gas
falls, other market participants that utilize natural gas-fired generation will
be able to offer electricity at increasingly competitive prices relative to our
off-system sales prices, so the margins we realize from sales will be lower and,
on occasion, we may need to curtail operation of marginal plants.

The price
trends for coal, natural gas and emission allowances have shown material
increases in the recent past. Changes in the cost of coal,
emission allowances or natural gas and changes in the relationship between such
costs and the market prices of power will affect our financial
results. Since the prices we obtain for power may not change at the
same rate as the change in coal, emission allowances or natural gas costs, we
may be unable to pass on the changes in costs to our customers.

In
addition, actual power prices and fuel costs will differ from those assumed in
financial projections used to value our trading and marketing transactions, and
those differences may be material. As a result, our financial results
may be diminished in the future as those transactions are marked to
market.

In Ohio, we have limited ability to
pass on our fuel costs to our customers. (Applies to AEP, CSPCo
and OPCo.)

Because
generation is no longer regulated in Ohio, we are exposed to risk from changes
in the market prices of coal, natural gas, and emissions allowances used to
generate power. The prices of coal, natural gas and emissions
allowances have increased materially in the recent past. The
protection afforded by retail fuel clause recovery mechanisms has been
eliminated by the implementation of customer choice in Ohio, which represents
approximately 20% of our fuel costs. As long as generating costs
cannot be passed through to customers as a matter of right in Ohio, we retain
these risks. If we cannot recover an amount sufficient to cover our
actual fuel costs, our results of operations and cash flows would be adversely
affected.

Risks
Relating to State Restructuring

There is uncertainty as to our
recovery of stranded costs resulting from industry restructuring in
Texas. (Applies to
AEP.)

Restructuring
legislation in Texas required utilities with stranded costs to use market-based
methods to value certain generating assets for determining stranded
costs. We elected to use the sale of assets method to determine the
market value of TCC’s generation assets for stranded cost
purposes. In general terms, the amount of stranded costs under this
market valuation methodology is the amount by which the book value of generating
assets, including regulatory assets and liabilities that were not securitized,
exceeds the market value of the generation assets, as measured by the net
proceeds from the sale of the assets. In May 2005, TCC filed its stranded cost
quantification application with the PUCT seeking recovery of $2.4 billion of net
stranded generation costs and other recoverable true-up items. A
final order was issued in April 2006. In the final order, the PUCT
determined TCC’s net stranded generation costs and other recoverable true-up
items to be approximately $1.475 billion. We have appealed the PUCT’s
final order seeking additional recovery consistent with the Texas Restructuring
Legislation and related rules, other parties have appealed the PUCT’s final
order as unwarranted or too large. Management cannot predict the ultimate
outcome of any future court appeals or any future remanded PUCT
proceeding.

Collection of our revenues in Texas
is concentrated in a limited number of REPs.(Applies to
AEP.)

Our
revenues from the distribution of electricity in the ERCOT area of Texas are
collected from REPs that supply the electricity we distribute to their
customers. Currently, we do business with approximately seventy
REPs. In 2008, TCC’s largest customer accounted for 28% of its
operating revenues; TNC’s largest customer (a non-utility affiliate) accounted
for 28% of its operating revenues and its second largest customer accounted for
12% of its operating revenues. Adverse economic conditions,
structural problems in the Texas market or financial difficulties of one or more
REPs could impair the ability of these REPs to pay for our services or could
cause them to delay such payments. We depend on these REPs for timely
remittance of payments. Any delay or default in payment could
adversely affect the timing and receipt of our cash flows and thereby have an
adverse effect on our liquidity.

Risks
Related to Owning and Operating Generation Assets and Selling Power

Our costs of compliance with
environmental laws are significant and the cost of compliance with future
environmental laws could harm our cash flow and profitability or cause some of
our electric generating units to be uneconomical to maintain or operate.
(Applies to each
registrant)

Our
operations are subject to extensive federal, state and local environmental
statutes, rules and regulations relating to air quality, water quality, waste
management, natural resources and health and safety. Approximately
90% of the electricity generated by the AEP system is produced by the combustion
of fossil fuels. Emissions of nitrogen and sulfur oxides, mercury and
particulates from fossil fueled generating plants are potentially subject to
increased regulations, controls and mitigation expenses. Compliance
with these legal requirements requires us to commit significant capital toward
environmental monitoring, installation of pollution control equipment, emission
fees and permits at all of our facilities. These expenditures have
been significant in the past, and we expect that they will increase in the
future. Further, environmental advocacy groups, other organizations
and some agencies in the United States are focusing considerable attention on
CO2
emissions from power generation facilities and their potential role in climate
change. Although several bills have been introduced in Congress that
would compel CO2 emission
reductions, none have advanced through the legislature. In April 2007
the U.S. Supreme Court determined that CO2 is an “air
pollutant” and that the Federal EPA has authority to regulate CO2 emissions
under the CAA. In July 2008 the Federal EPA issued an advance notice
of proposed rulemaking (ANPR) that requests comments on a wide variety of issues
in response to the U.S. Supreme Court’s decision. The ANPR could lead
to regulations limiting the emissions of CO2 from our
generating plants. In addition, the Obama administration has
indicated that it intends to focus on reducing CO2emissions.

Costs of
compliance with environmental regulations could adversely affect our net income
and financial position, especially if emission and/or discharge limits are
tightened, more extensive permitting requirements are imposed, additional
substances become regulated and the number and types of assets we operate
increase. All of our estimates are subject to significant
uncertainties about the outcome of several interrelated assumptions and
variables, including timing of implementation, required levels of reductions,
allocation requirements of the new rules and our selected compliance
alternatives. As a result, we cannot estimate our compliance costs
with certainty. The actual costs to comply could differ significantly
from our estimates. All of the costs are incremental to our current
investment base and operating cost structure. In addition, any legal
obligation that would require us to substantially reduce our emissions beyond
present levels could require extensive mitigation efforts and, in the case of
CO2
legislation, would raise uncertainty about the future viability of fossil fuels,
particularly coal, as an energy source for new and existing electric generation
facilities. While we expect to recover our expenditures for pollution
control technologies, replacement generation and associated operating costs from
customers through regulated rates (in regulated jurisdictions) or market prices,
without such recovery those costs could adversely affect future net income and
cash flows, and possibly financial condition.

Governmental authorities may assess
penalties on us if it is determined that we have not complied with environmental
laws and regulations. (Applies to each
registrant.)

If we
fail to comply with environmental laws and regulations, even if caused by
factors beyond our control, that failure may result in the assessment of civil
or criminal penalties and fines against us. In July 2004 attorneys
general of eight states and others sued AEP and other utilities alleging that
CO2
emissions from power generating facilities constitute a public nuisance under
federal common law. The trial court dismissed the suits and
plaintiffs have appealed the dismissal. While we believe the claims
are without merit, the costs associated with reducing CO2 emissions
could harm our business and our results of operations and financial
position.

If these
or other future actions are resolved against us, substantial modifications of
our existing coal-fired power plants could be required. In addition,
we could be required to invest significantly in additional emission control
equipment, accelerate the timing of capital expenditures, pay penalties and/or
halt operations. Moreover, our results of operations and financial
position could be reduced due to the timing of recovery of these investments and
the expense of ongoing litigation.

Our financial performance may be
impaired if Cook Plant Unit 1 is not returned to service in a reasonable period
of time or in a cost-efficient manner. (Applies to AEP and
I&M)

Cook
Plant Unit 1 is a 1,055 MW nuclear generating unit located in Bridgman,
Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations,
likely caused by blade failure, which resulted in a fire on the electric
generator. I&M is working with its insurance company and turbine
vendor to evaluate the extent of the damage resulting from the incident and the
costs to return the unit to service. Repair and replacement of the
turbine rotors is estimated to cost up to approximately $330
million. Management believes that I&M should recover a
significant portion of these costs through the turbine vendor’s warranty,
insurance and the regulatory process. If any of these costs are not
covered by warranty, insurance or recovered through the regulatory process, or
if the unit is not returned to service in a reasonable period of time, it could
have an adverse impact on net income, cash flows and financial
condition.

Our revenues and results of
operations from selling power are subject to market risks that are beyond our
control. (Applies to each
registrant.)

We sell
power from our generation facilities into the spot market or other competitive
power markets or on a contractual basis. We also enter into contracts
to purchase and sell electricity, natural gas, emission allowances and coal as
part of our power marketing and energy trading operations. With
respect to such transactions, the rate of return on our capital investments is
not determined through mandated rates, and our revenues and results of
operations are likely to depend, in large part, upon prevailing market prices
for power in our regional markets and other competitive
markets. These market prices can fluctuate substantially over
relatively short periods of time. Trading margins may erode as
markets mature and there may be diminished opportunities for gain should
volatility decline. In addition, the FERC, which has jurisdiction
over wholesale power rates, as well as RTOs that oversee some of these markets,
may impose price limitations, bidding rules and other mechanisms to address some
of the volatility in these markets. Power supply and other similar
agreements entered into during extreme market conditions may subsequently be
held to be unenforceable by a reviewing court or the FERC. Fuel and
emissions prices may also be volatile, and the price we can obtain for power
sales may not change at the same rate as changes in fuel and/or emissions
costs. These factors could reduce our margins and therefore diminish
our revenues and results of operations.

federal,
state and foreign energy and environmental regulation and
legislation.

Our power trading (including coal,
gas and emission
allowances trading and
power marketing) and risk management policies cannot eliminate the risk
associated with these activities. (Applies to each
registrant.)

Our power
trading (including coal, gas and emission allowances trading and power
marketing) activities expose us to risks of commodity price
movements. We attempt to manage our exposure by establishing and
enforcing risk limits and risk management procedures. These risk
limits and risk management procedures may not work as planned and cannot
eliminate the risks associated with these activities. As a result, we
cannot predict the impact that our energy trading and risk management decisions
may have on our business, operating results or financial position.

We
routinely have open trading positions in the market, within guidelines we set,
resulting from the management of our trading portfolio. To the extent
open trading positions exist, fluctuating commodity prices can improve or
diminish our financial results and financial position.

Our power
trading and risk management activities, including our power sales agreements
with counterparties, rely on projections that depend heavily on judgments and
assumptions by management of factors such as the future market prices and demand
for power and other energy-related commodities. These factors become
more difficult to predict and the calculations become less reliable the further
into the future these estimates are made. Even when our policies and
procedures are followed and decisions are made based on these estimates, results
of operations may be diminished if the judgments and assumptions underlying
those calculations prove to be inaccurate.

Our financial performance may be
adversely affected if we are unable to operate our pooled electric generating
facilities successfully. (Applies to each
registrant.)

catastrophic
events such as fires, earthquakes, explosions, hurricanes, terrorism,
floods or other similar
occurrences.

A
decrease or elimination of revenues from power produced by our electric
generating facilities or an increase in the cost of operating the facilities
would adversely affect our results of operations.

Parties with whom we have contracts
may fail to perform their obligations, which could harm our results of
operations. (Applies to each
registrant.)

We are
exposed to the risk that counterparties that owe us money or power could breach
their obligations. Should the counterparties to these arrangements
fail to perform, we may be forced to enter into alternative hedging arrangements
or honor underlying commitments at then-current market prices that may exceed
our contractual prices, which would cause our financial results to be diminished
and we might incur losses. Although our estimates take into account the expected
probability of default by a counterparty, our actual exposure to a default by a
counterparty may be greater than the estimates predict.

We rely on electric transmission
facilities that we do not own or control. If these facilities do not
provide us with adequate transmission capacity, we may not be able to deliver
our wholesale electric power to the purchasers of our power. (Applies to each
registrant.)

We depend
on transmission facilities owned and operated by other unaffiliated power
companies to deliver the power we sell at wholesale. This dependence
exposes us to a variety of risks. If transmission is disrupted, or
transmission capacity is inadequate, we may not be able to sell and deliver our
wholesale power. If a region’s power transmission infrastructure is
inadequate, our recovery of wholesale costs and profits may be
limited. If restrictive transmission price regulation is imposed, the
transmission companies may not have sufficient incentive to invest in expansion
of transmission infrastructure.

The FERC
has issued electric transmission initiatives that require electric transmission
services to be offered unbundled from commodity sales. Although these
initiatives are designed to encourage wholesale market transactions for
electricity and gas, access to transmission systems may in fact not be available
if transmission capacity is insufficient because of physical constraints or
because it is contractually unavailable. We also cannot predict
whether transmission facilities will be expanded in specific markets to
accommodate competitive access to those markets.

We do not fully hedge against price
changes in commodities. (Applies to each
registrant.)

We
routinely enter into contracts to purchase and sell electricity, natural gas,
coal and emission allowances as part of our power marketing and energy and
emission allowances trading operations. In connection with these
trading activities, we routinely enter into financial contracts, including
futures and options, over-the counter options, financially-settled swaps and
other derivative contracts. These activities expose us to risks from
price movements. If the values of the financial contracts change in a
manner we do not anticipate, it could harm our financial position or reduce the
financial contribution of our trading operations.

We manage
our exposure by establishing risk limits and entering into contracts to offset
some of our positions (i.e., to hedge our exposure to demand, market effects of
weather and other changes in commodity prices). However, we do not
always hedge the entire exposure of our operations from commodity price
volatility. To the extent we do not hedge against commodity price
volatility, our results of operations and financial position may be improved or
diminished based upon our success in the market.

ITEM
1B. UNRESOLVED STAFF
COMMENTS

None.

ITEM
2. PROPERTIES

GENERATION
FACILITIES

UTILITY
OPERATIONS

At
December 31, 2008, the AEP System owned (or leased where indicated) generating
plants with net power capabilities (winter rating) shown in the following
table:

Company

Stations

Coal

MW

Natural
Gas

MW

Nuclear

MW

Lignite

MW

Hydro

MW

Oil

MW

Total

MW

AEGCo

2

(a)

1,310

1,146

2,456

APCo

17

(b)(c)

5,093

516

681

6,290

CSPCo

7

(d)

2,341

1,357

3

3,701

I&M

9

(a)

2,305

2,191

15

4,511

KPCo

1

1,060

1,060

OPCo

8

(b)(c)(e)

8,452

26

8,478

PSO

8

(f)(g)

1,026

3,552

25

4,603

SWEPCo

10

(h)

1,848

2,152

850

4,850

TNC

6

(f)
(i)(j)

377

262

8

647

System
Totals

62

23,812

8,985

2,191

850

722

36

36,596

Percentage
of System Totals

65.1

24.5

6.0

2.3

2.0

0.1

(a)

Unit
1 of the Rockport Plant is owned one-half by AEGCo and one-half by
I&M. Unit 2 of the Rockport Plant is leased one-half by AEGCo and
one-half by I&M. The leases terminate in 2022 unless
extended.

(b)

Unit
3 of the John E. Amos Plant is owned one-third by APCo and two-thirds by
OPCo.

CSPCo
owns generating units in common with Duke Ohio and DP&L. Its
percentage ownership interest is reflected in this
table.

(e)

The
scrubber facilities at the General James M. Gavin Plant are
leased. OPCo is permitted to terminate the lease as early as
2010.

(f)

As
of December 31, 2008, PSO and TNC, along with Oklahoma Municipal Power
Authority and The Public Utilities Board of the City of Brownsville,
Texas, jointly owned the Oklaunion power station. PSO and TNC’s ownership
interest is reflected in this portion of the table.

(g)

PSO
began commercial operation of Units 4 and 5, of 85 MW each (winter
rating), at its gas-fired Southwestern Plant in February 2008. Also,
commercial operation of PSO’s Units 3 and 4, of 85 MW each (winter
rating), at the gas-fired Riverside Plant began in April
2008.

(h)

SWEPCo
owns generating units in common with Cleco Corporation and other
unaffiliated parties. Only its ownership interest is reflected in this
table.

(i)

TNC
sold the four inactive plants of Fort Phantom, Lake Pauline, San Angelo,
and Rio Pecos to Eagle Construction and Environmental Services, LP for a
total of 667 MW (winter rating) in February 2008. A fifth inactive plant
owned by TNC, the Oak Creek Plant (85 MW, winter rating), was conveyed to
the City of Sweetwater under terms related to a settlement agreement
executed by the parties in 2005.

(j)

TNC’s
gas-fired and oil-fired generation has been
deactivated.

Cook
Nuclear Plant

The
following table provides operating information relating to the Cook
Plant.

Costs
associated with the operation (including fuel), maintenance and retirement of
nuclear plants continue to be more significant and less predictable than costs
associated with other sources of generation, in large part due to changing
regulatory requirements and safety standards, availability of nuclear waste
disposal facilities and experience gained in the operation of nuclear
facilities. The ability of I&M to obtain adequate and timely
recovery of costs associated with the Cook Plant is not assured. Such
costs may include replacement power, any unamortized investment at the end of
the useful life of the Cook Plant (whether scheduled or premature), the carrying
costs of that investment and retirement costs.

GENERATION
AND MARKETING

In
addition to the generating facilities described above, AEP has ownership
interests in other electrical generating facilities. Information concerning
these facilities at December 31, 2008 is listed below.

Facility

Fuel

Location

Capacity

Total MW

Owner-ship

Interest

Status

Desert
Sky Wind Farm

Wind

Texas

161

100%

Exempt
Wholesale Generator(a)

Trent
Wind Farm

Wind

Texas

150

100%

Exempt
Wholesale Generator(a)

Total

311

(a) As
defined under rules issued pursuant to EPACT.

See
Note 7 to the consolidated financial statements entitled Acquisitions, Dispositions,
Discontinued Operations and Impairments, included in the 2008 Annual
Reports, for a discussion of AEP’s disposition of independent power producer and
foreign generation assets.

TRANSMISSION AND
DISTRIBUTION FACILITIES

The
following table sets forth the total overhead circuit miles of transmission and
distribution lines of the AEP System and its operating companies and that
portion of the total representing 765kV lines:

Total
Overhead Circuit Miles of Transmission and Distribution
Lines

Circuit
Miles of

765kV
Lines

AEP
System (a)

224,095

(b)

2,116

APCo

52,022

734

CSPCo
(a)

15,519

—

I&M

22,023

615

Kingsport
Power Company

1,358

—

KPCo

11,020

258

OPCo

30,762

509

PSO

21,193

—

SWEPCo

21,453

—

TCC

29,564

—

TNC

17,476

—

WPCo

1,705

—

(a)

Includes
766 miles of 345,000-volt jointly owned
lines.

(b)

Includes
73 miles of overhead transmission lines not identified with an operating
company.

TITLES

The AEP
System’s generating facilities are generally located on lands owned in fee
simple. The greater portion of the transmission and distribution lines of the
System has been constructed over lands of private owners pursuant to easements
or along public highways and streets pursuant to appropriate statutory
authority. The rights of AEP’s public utility subsidiaries in the realty on
which their facilities are located are considered adequate for use in the
conduct of their business. Minor defects and irregularities customarily found in
title to properties of like size and character may exist, but such defects and
irregularities do not materially impair the use of the properties affected
thereby. AEP’s public utility subsidiaries generally have the right of eminent
domain which permits them, if necessary, to acquire, perfect or secure titles to
or easements on privately held lands used or to be used in their utility
operations. Recent legislation in Ohio and Virginia has restricted
the right of eminent domain previously granted for power generation
purposes.

SYSTEM TRANSMISSION LINES
AND FACILITY SITING

Laws in
the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Texas,
Tennessee, Virginia, and West Virginia require prior approval of sites of
generating facilities and/or routes of high-voltage transmission lines. We have
experienced delays and additional costs in constructing facilities as a result
of proceedings conducted pursuant to such statutes, and in proceedings in which
our operating companies have sought to acquire rights-of-way through
condemnation. These proceedings may result in additional delays and
costs in future years. See Management’s Financial Discussion
and Analysis of Results of Operations included in the 2008 Annual
Reports, for more information on current siting proceedings.

CONSTRUCTION
PROGRAM

GENERAL

With
input from its state utility commissions, the AEP System continuously
assesses the adequacy of its generation, transmission, distribution and
other facilities to plan and provide for the reliable supply of electric
power and energy to its customers. In this assessment process, assumptions
are continually being reviewed as new information becomes available, and
assessments and plans are modified, as appropriate. AEP
forecasts $2.6 billion of construction expenditures, excluding AFUDC, for
2009, which is a significant reduction from the original 2009 capital
forecast set in 2008. Estimated construction expenditures are
subject to periodic review and modification and may vary based on the
ongoing effects of regulatory constraints, environmental regulations,
business opportunities, market volatility, economic trends, and the
ability to access capital. Due to recent credit market
instability, we reviewed our projections for capital expenditures for 2009
and 2010. We identified reductions of approximately $750
million for 2009. We are evaluating possible additional
capital reductions for 2010.

PROPOSED
TRANSMISSION FACILITIES

Joint
Venturein
PJM

In June
2007, PJM authorized the construction of a major new transmission line to
address the reliability and efficiency needs of the PJM system. The
line would be 765kV and would run approximately 275 miles from APCo’s Amos
substation in West Virginia to Allegheny Energy Inc.’s (“AYE”) proposed Kemptown
station in north central Maryland. In September 2007, AEP and AYE
entered into a joint venture to construct, own and operate transmission
facilities in the PJM region, including the Amos-to-Kemptown transmission line.
In December 2007, the joint venture filed an application with the FERC for
approval of a return on equity and formula rate for the Amos-to-Kemptown
transmission line. FERC approval of the settlement among the
participants is pending. In addition to the rate recovery sought
through the FERC, the joint venture will seek appropriate regulatory approvals
from the appropriate state utility commissions for siting and Certificates of
Public Convenience and Necessity. The total cost of the
Amos-to-Kemptown line is estimated to be approximately $1.8 billion, and AEP’s
estimated share will be approximately $600 million. The joint venture
is not consolidated with AEP for financial or tax reporting
purposes. See Management’s Financial Discussion
and Analysis of Results of Operations included in the 2008 Annual Reports
for more information.

Joint
Venture in ERCOT

In January 2007, TCC entered into an
agreement to establish a joint venture with MidAmerican Energy Holdings Company
(“MidAmerican”) to fund, own and operate electric transmission assets in
ERCOT. In January 2007, a filing was made with the PUCT seeking
regulatory approval to operate as an electric transmission utility in Texas, to
transfer transmission assets from TCC to the joint venture and to establish a
wholesale transmission tariff. In December 2007, the PUCT issued an
order authorizing the transaction, the initial tariffs and a certificate of
convenience and necessity to operate in the ERCOT region. A Texas district court
reversed the PUCT’s order granting a certificate of convenience. Both
the PUCT and ETT have appealed this decision. The PUCT’s appeal
suspends enforceability of the court’s judgment pending final appellate
review. Subsidiaries of AEP and MidAmerican each hold a 50 percent
equity interest in the joint venture. The joint venture is not
consolidated with AEP for financial or tax reporting purposes. See
Management’s Financial
Discussion and Analysis of Results of Operations, Note 4and Note 7 to the
consolidated financial statements, entitled Rate Matter and Acquisitions, Dispositions,
Discontinued Operations and Impairments, respectively, included in the
2008 Annual Reports, for more information.

PROPOSED
GENERATION FACILITIES

SWEPCo
Projects

In 2008,
SWEPCo began construction of a 508 MW combined-cycle natural gas fired plant at
its existing Arsenal Hill Power Plant in Shreveport, Louisiana (the “Stall
Unit”). PUCT and LPSC have approved construction of the Stall Unit
and filing has been made with the APSC seeking approval to construct the Stall
Unit. The Stall Unit is estimated to cost $384 million, excluding
AFUDC, and is expected to be operational in mid-2010. See Note 4 to
the consolidated financial statements, entitled Rate Matters, included in the
2008 Annual Reports, for more information.

In August
2006, SWEPCo announced plans to build a new base load 600 MW pulverized coal
ultra-supercritical generating unit in Arkansas named the John W. Turk, Jr.
Power Plant (the “Turk Plant”). In 2008, SWEPCo received various
regulatory approvals, including the issuance of an air permit from the Arkansas
Department of Environmental Quality, to construct the Turk Plant and actual
construction commenced in November 2008. SWEPCo anticipates owning
73% of the Turk Plant and will be the operator. During 2007, SWEPCO
signed joint ownership, construction and operations agreements with Oklahoma
Municipal Power Authority, AECC and ETEC for the remaining 27% of the Turk
Plant. ETEC’s participation in the Turk Plant is contingent on obtaining
certain regulatory approvals that are pending. The Turk Plant is
estimated to cost $1.6 billion with SWEPCo’s 73% portion estimated to cost $1.2
billion, excluding AFUDC. The Turk Plant is expected to be
operational in 2013. See Note 4 to the consolidated financial
statements, entitled Rate
Matters, included in the 2008 Annual Reports, for more
information.

Ohio
IGCC Plant

In March
2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority
to recover costs related to building and operating a 629 MW IGCC power plant
using clean-coal technology. In June 2006, the PUCO issued an order
approving a tariff to recover pre-construction costs, subject to
refund. In March 2008, the Ohio Supreme Court remanded the matter
back to the PUCO after review. Pending the outcome of the
remand, neither CSPCo nor OPCo are engaged in a continuous course of
construction on the IGCC plant. In December 2007 we estimated that
its construction would cost $2.7 billion. Since then costs to
construct generation facilities have continued to increase
significantly. Management continues to pursue the ultimate
construction of the IGCC plant. However, CSPCo and OPCo will not
start construction of the IGCC plant until sufficient assurance of regulatory
cost recovery exists.See Management’s Financial Discussion
and Analysis of Results of Operations and Note 4 to the consolidated
financial statements, entitled Rate Matters, included in the
2008 Annual Reports, for more information.

West
Virginia IGCC

In
January 2006, APCo filed a petition with the WVPSC requesting its approval of a
Certificate of Public Convenience and Necessity (CCN) to construct a proposed
629 MW IGCC plant. The plant is to be built adjacent to APCo’s
existing Mountaineer Generating Station in Mason County, WV for an estimated
cost of $2.2 billion. In March 2008, the WVPSC granted APCo the CCN
to build the plant and approved the requested cost recovery. In July
2007, APCo filed a request with the VSCC for a rate adjustment clause to recover
initial costs associated with a proposed IGCC plant. The VSCC issued
an order in April 2008 denying APCo’s requests, in part, upon its finding that
the estimated cost of the plant was uncertain and may escalate. In
July 2008, based on the unfavorable order received in Virginia, the WVPSC issued
a notice seeking comments from parties on how the WVPSC should
proceed. Comments were filed by various parties, including APCo, but
the WVPSC has not taken any action. See Management’s Financial Discussion
and Analysis of Results of Operations and Note 4 to the consolidated
financial statements, entitled Rate Matters, included in the
2008 Annual Reports, for more information.

Mountaineer
Carbon Capture Project

In
January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party,
entered into an agreement to jointly construct a 20 MW CO2 capture
demonstration facility at APCo’s Mountaineer 1320 MW generating
unit. APCo and Alstom will each own part of the CO2 capture
facility. APCo will also construct and own the necessary facilities
to store the CO2. RWE
AG, a German electric power and natural gas public utility, is participating in
the evaluation of the commercial and technical feasibility of taking captured
CO2
from the flue gas stream and storing it in deep geologic
formations. APCo’s estimated cost for its share of the facilities is
$76 million. Through December 31, 2008, APCo incurred $29 million in
capitalized project costs that are included in regulatory
assets. APCo is earning a return on the capitalized project costs
incurred through June 30, 2008, as a result of the base rate case settlement
approved by the VSCC in November 2008.See Note 4 to the
consolidated financial statements, entitled Rate Matters, included in the
2008 Annual Reports, for more information.

Other

Our
significant planned environmental investments in emission control installations
at existing coal-fired plants and our commitment to IGCC and ultra-supercritical
technology reinforce our belief that coal will be a lower-emission domestic
energy source of the future and further signals our commitment to invest in
clean, environmentally safe technology. For additional
information regarding anticipated environmental expenditures, see Management’s Financial Discussion
and Analysis of Results of Operations under the heading entitled Environmental
Matters.

CONSTRUCTION
EXPENDITURES

The
following table shows construction expenditures (including environmental
expenditures) during 2006, 2007 and 2008 and a current estimate of 2009
construction expenditures, in each case excluding AFUDC, capitalized interest
and assets acquired under leases.

2006

Actual
(b)

2007

Actual
(c)

2008

Actual
(d)

2009

Estimate

(in
thousands)

Total
AEP System (a)

$3,551,000

$3,414,000

$3,981,200

$2,584,000

APCo

922,700

715,700

755,800

367,500

CSPCo

325,000

330,800

435,700

269,600

I&M

306,900

282,400

372,400

361,600

OPCo

978,600

806,000

675,200

439,400

PSO

245,200

302,600

274,200

187,700

SWEPCo

339,400

516,800

689,300

457,400

(a)

Includes
expenditures of other subsidiaries not shown. The figures reflect
construction expenditures, not investments in subsidiary
companies. Excludes discontinued
operations.

The
System construction program is reviewed continuously and is revised from time to
time in response to changes in estimates of customer demand, business and
economic conditions, the cost and availability of capital, environmental
requirements and other factors. Changes in construction schedules and costs, and
in estimates and projections of needs for additional facilities, as well as
variations from currently anticipated levels of net earnings, Federal income and
other taxes, and other factors affecting cash requirements, may increase or
decrease the estimated capital requirements for the System’s construction
program. Due to recent credit market instability, we reviewed our
projections for capital expenditures for 2009 and 2010. We identified
reductions of approximately $750 million for 2009. We are evaluating
possible additional capital reductions for 2010.

POTENTIAL UNINSURED
LOSSES

Some
potential losses or liabilities may not be insurable or the amount of insurance
carried may not be sufficient to meet potential losses and liabilities,
including liabilities relating to damage to our generating plants and costs of
replacement power. Unless allowed to be recovered through rates, future losses
or liabilities which are not completely insured could have a material adverse
effect on results of operations and the financial condition of AEP and other AEP
System companies. For risks related to owning a nuclear generating unit, see
Note 9 to the consolidated financial statements entitled Nuclear for information with
respect to nuclear incident liability insurance.

ITEM
3. LEGAL
PROCEEDINGS

For a
discussion of material legal proceedings, see Note 6 to the consolidated
financial statements, entitled Commitments, Guarantees and
Contingencies, incorporated by reference in Item 8.

ITEM
4. SUBMISSION
OF MATTERS TO A VOTE

OF SECURITY
HOLDERS

AEP, APCo, OPCo, PSO and SWEPCo. None.

CSPCo and I&M. Omitted pursuant to
Instruction I(2)(c).

EXECUTIVE OFFICERS OF THE
REGISTRANTS

AEP. The following
persons are, or may be deemed, executive officers of AEP. Their ages are
given as of February 1, 2009.

Name

Age

Office (a)

Michael
G. Morris

62

Chairman
of the Board, President and Chief Executive Officer

Nicholas
K. Akins

48

Executive
Vice President

Carl
L. English

62

Chief
Operating Officer

John
B. Keane

62

Executive
Vice President, General Counsel and Secretary

Holly
Keller Koeppel

50

Executive
Vice President and Chief Financial Officer

Venita
McCellon-Allen

49

Executive
Vice President

Richard
E. Munczinski

56

Senior
Vice President

Robert
P. Powers

54

President-AEP
Utilities

Brian
X. Tierney

41

Executive
Vice President

Susan
Tomasky

55

President
– AEP Transmission

(a)

Messrs.
Morris, Akins, Munczinski, Powers and Tierney and Ms. Koeppel and Ms.
Tomasky have been employed by AEPSC or System companies in various
capacities (AEP, as such, has no employees) for the past five
years. Messrs. Akins, Munczinski, Powers and
Tierney, Ms. Koeppel and Ms. Tomasky became executive officers of AEP
effective with their promotions on August 15, 2006, June 1, 2008, October
24, 2001, January 1, 2008, November 18, 2002 and January 26, 2000,
respectively. Mr. Keane became an executive officer of AEP in July
2004. Before joining AEPSC in July 2004, Mr. Keane was
President of Bainbridge Crossing Advisors. Mr. English became
an executive officer of AEP on August 1, 2004. Before joining
AEPSC in August 2004, Mr. English was President and Chief Executive
Officer of Consumers Energy gas division. Ms. McCellon-Allen became
an executive officer of AEP in July 2008. From August 2006 to
June 2008, Ms. McCellon-Allen was President and Chief Operating Officer of
SWEPCO. Before joining AEPSC in 2004, Ms. McCellon-Allen was
SVP-Human Resources for Baylor Heath Care Systems. All of the
above officers are appointed annually for a one-year term by the board of
directors of AEP.

APCo, OPCo, PSO and SWEPCo. The
names of the executive officers of APCo, OPCo, PSO and SWEPCo, the positions
they hold with these companies, their ages as of February 1, 2009, and a brief
account of their business experience during the past five years appear below.
The directors and executive officers of APCo, OPCo, PSO and SWEPCo are elected
annually to serve a one-year term.

Name

Age

Position

Period

Michael
G. Morris (a)(b)

62

Chairman
of the Board, President, Chief Executive Officer and Director of
AEP

2004-Present

Chairman
of the Board, Chief Executive Officer and Director of APCo, OPCo, PSO and
SWEPCo

2004-Present

Nicholas
K. Akins (a)

48

Executive
Vice President of AEP

2006-Present

Vice
President and Director of APCo, OPCo, PSO

2006-Present

and
SWEPCo

President
and Chief Operating Officer of SWEPCo

2004-2006

Carl
L. English (a)

62

Chief
Operating Officer

2008-Present

President-AEP
Utilities of AEP

2004-2007

Director
and Vice President of APCo, OPCo, PSO and SWEPCo

2004-Present

President
and Chief Executive Officer of Consumers Energy gas
division

1999-2004

John
B. Keane (c)

62

Executive
Vice President, General Counsel and Secretary of AEP

2004-Present

Director
of APCo, OPCo , PSO and SWEPCo

2004-Present

President
of Bainbridge Crossing Advisors

2003-2004

Holly
Keller Koeppel (a)(d)

50

Executive
Vice President and Chief Financial Officer of AEP

2006-Present

Executive
Vice President-AEP Utilities-East of AEPSC

2004-2006

Vice
President of APCo and OPCo

2003-Present

Director
of APCo and OPCo

2004-Present

Chief
Financial Officer of APCo, OPCo, PSO and SWEPCo

2006-Present

Vice
President and Director of PSO and SWEPCo

2006-Present

Executive
Vice President-Commercial Operations of AEPSC

2002-2004

Venita
McCellon-Allen

49

Executive
Vice President

2008-Present

Director
and Vice President of PSO and SWEPCo

2008-Present

President
and Chief Operating Officer of SWEPCo

2006-2008

Director
and Senior Vice President-Shared Services of AEPSC

2004-2006

Director
of APCo, I&M, OPCo and SWEPCo

2004-2006

Senior
Vice President-Human Resources for Baylor Health Care
Systems

2000-2004

Richard
E. Munczinski (c)

56

Senior
Vice President-Shared Services

2008-Present

Senior
Vice President-Corporate Planning & Budgeting of AEPSC

1998-2008

Robert
P. Powers (a)

54

President-AEP
Utilities of AEP

2008-Present

Executive
Vice President of AEP

2004-2007

Director
and Vice President of APCo and OPCo

2001-Present

Director
and Vice President of PSO and SWEPCo

2008-Present

Brian
X. Tierney (a)

41

Executive
Vice President

2008-Present

Director
and Vice President of APCo and OPCo

2008-Present

Senior
Vice President—Commercial Operations of AEPSC

2005-2007

Senior
Vice President— Energy Marketing of AEPSC

2003-2005

Susan
Tomasky (a)

55

President-AEP
Transmission

2008-Present

Executive
Vice President of AEP

2004-Present

Chief
Financial Officer of AEP

2001-2006

Vice
President and Director of APCo, OPCo, PSO and SWEPCo

2000-Present

(a)

Messrs.
Morris, Akins, English, Powers and Tierney and Ms. Koeppel and Ms.
Tomasky are directors of CSPCo and I&M.

(b)

Mr.
Morris is a director of Alcoa, Inc. and The Hartford Financial Services
Group, Inc.

(c)

Mr.
Keane and Mr. Munczinski are directors of CSPCo.

(d)

Ms.
Koeppel is a director of Reynolds American
Inc.

APCo:

Name

Age

Position

Period

Dana
E. Waldo

57

President
and Chief Operating Officer of APCo

2004-Present

President
and Chief Executive Officer of West Virginia Roundtable

1999-2004

OPCo:

Name

Age

Position

Period

Joseph
Hamrock

45

President
and Chief Operating Officer of CSPCo and OPCo

2008-Present

Senior
Vice President and Chief Information Officer of AEPSC

2003-2007

PSO:

Name

Age

Position

Period

Stuart
Solomon

47

President
and Chief Operating Officer of PSO

2004-Present

Vice
President-Public Policy & Regulatory Services of AEPSC

2001-2004

SWEPCo:

Name

Age

Position

Period

Paul
Chodak, III

45

President
and Chief Operating Officer of SWEPCo

2008-Present

Director-New
Generation of AEPSC

2007-2008

Director-Environmental
Programs of AEPSC

2004-2007

Director-Environmental
Programs of AEPSC

2004-2007

PART
II

ITEM
5. MARKET
FOR REGISTRANTS’ COMMON EQUITY,

RELATED
STOCKHOLDER MATTERS

AND ISSUER PURCHASES OF EQUITY
SECURITIES

AEP. The information required
by this item is incorporated herein by reference to the material under AEP Common Stock and Dividend
Information in the 2008 Annual Report.

APCo, CSPCo, I&M, OPCo, PSO and
SWEPCo. The common stock of these companies is held solely by AEP. The
amounts of cash dividends on common stock paid by these companies to AEP during
2008, 2007 and 2006 are incorporated by reference to the material under Statements of Changes in Common
Shareholder’s Equity and Comprehensive Income (Loss) in the 2008 Annual
Reports.

The
following table provides information about purchases by AEP (or its
publicly-traded subsidiaries) during the quarter ended December 31, 2008 of
equity securities that are registered by AEP (or its publicly-traded
subsidiaries) pursuant to Section 12 of the Exchange Act:

ISSUER
PURCHASES OF EQUITY SECURITIES

Period

Total

Number

of
Shares

Purchased

Average

Price

Paid

per
Share

Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs

Maximum
Number

(or
Approximate Dollar Value) of Shares that May Yet Be

Purchased
Under the Plans or Programs

10/01/08
– 10/31/08

-

$

-

-

$

-

11/01/08
– 11/30/08

-

-

-

-

12/01/08
– 12/31/08

-

-

-

-

Total

-

$

-

-

$

-

ITEM
6. SELECTED
FINANCIAL DATA

CSPCo and I&M. Omitted pursuant
to Instruction I(2)(a).

AEP, APCo, OPCo, PSO and SWEPCo. The
information required by this item is incorporated herein by reference to the
material under Selected
Consolidated Financial Data in the 2008 Annual Reports.

ITEM
7. MANAGEMENT’S
DISCUSSION AND ANALYSIS

OF FINANCIAL
CONDITION

AND RESULTS OF
OPERATION

CSPCo and
I&M. Omitted pursuant to Instruction I(2)(a). Management’s
narrative analysis of the results of operations and other information required
by Instruction I(2)(a) is incorporated herein by reference to the material under
Management’s Financial
Discussion and Analysisof Results of Operations in
the 2008 Annual Reports.

AEP, APCo,
OPCo,
PSO and
SWEPCo. The
information required by this item is incorporated herein by reference to the
material under Management’s
Financial Discussion and Analysis of Results of Operations in the 2008 Annual
Reports.

ITEM
7A. QUANTITATIVE
AND QUALITATIVE

DISCLOSURES ABOUT
MARKET RISK

AEP, APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo. The information required by this item is incorporated herein
by reference to the material under Management’s Financial Discussion
and Analysis of Results of Operations in the 2008 Annual
Reports.

ITEM
8. FINANCIAL
STATEMENTS

AND SUPPLEMENTARY
DATA

AEP, APCo, CSPCo, I&M, OPCo, PSO
and SWEPCo. The information required by this item is incorporated herein
by reference to the financial statements and financial statement schedules
described under Item 15 herein.

ITEM
9. CHANGES
IN AND DISAGREEMENTS WITH

ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE

AEP, APCo, CSPCo, I&M, OPCo, PSO
and
SWEPCo. None.

ITEM
9A. CONTROLS
AND PROCEDURES

During
2008, management, including the principal executive officer and principal
financial officer of each of American Electric Power Company, Inc., Appalachian
Power Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric
Power Company (each a “Registrant” and collectively the “Registrants”) evaluated
each respective Registrant’s disclosure controls and
procedures. Disclosure controls and procedures are defined as
controls and other procedures of the Registrants that are designed to ensure
that information required to be disclosed by the Registrants in the reports that
they file or submit under the Exchange Act are recorded, processed, summarized
and reported within the time periods specified in the Commission’s rules and
forms. Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by the Registrants in the reports that they file or submit under
the Exchange Act is accumulated and communicated to each Registrant’s
management, including the principal executive and principal financial officers,
or persons performing similar functions, as appropriate to allow timely
decisions regarding required disclosure.